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lEEEStd 141-1993

(Revision of IEEE Std 141-1986)

IEEE Recommended Practice for
Electric Power Distribution
for Industrial Plants

Sponsor

Power Systems Engineering Committee
of the

Industrial and Commercial Power Systems Department
of the

IEEE Industry Applications Society

Approved December 2, 1993

IEEE Standards Board

Abstract: A thorough analysis of basic electrical-systems considerations is presented. Guid-
ance is provided in design, construction, and continuity of an overall system to achieve safety
of life and preservation of property; reliability; simplicity of operation; voltage regulation in the
utilization of equipment within the tolerance limits under all load conditions; care and mainte-
nance; and flexibility to permit development and expansion. Recommendations are made re-
garding system planning; voltage considerations; surge voltage protection; system protective
devices; fault calculations; grounding; power switching, transformation, and motor-control ap-
paratus; instruments and meters; cable systems; busways; electrical energy conservation; and
cost estimation.

Keywords: energy management, grounding, industrial power system, industrial power system
economics, industrial power system planning, industrial power system protection, power
cables, power distribution, power transformers, power system measurements, switches/
switchgear, wiring

Grateful acknowledgment is made to the following organizations for having granted permission to re-
print illustrations in this document as listed below:

Table 3-1 from ANSI C84. 1-1989, American National Standard for Electric Power Systems and Equip-
ment — Voltage Ratings (60 Hz), copyright 1989 by the American National Standards Institute.

Figure 3-7 from NEMA Standards Publication MG 1-1993, copyright held by the National Electrical
Manufacturers Association.

Figure 5-4 from Basler Electric. Highland, IL.

Figure 5-5 from General Electric Company, Malvern, PA.

Figure 6-6 from the Industrial Power Systems Data Book, General Electric Company, Schenectady, NY.
Figure 6-11 from D. L. Beeman, Ed., Industrial Power Systems Handbook. McGraw-Hill, New York, NY,
1955.

The Institute of Electrical and Electronics Engineers, Inc.

345 East 47th Street, New York, NY 10017-2394, USA

ISBN 1-55937-333-4

No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise,
without the prior written permission of the publisher.

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Introduction

(This introduction is not part of IEEE Std 141-1993, IEEE Recommended Practice for Electric Power
Distribution for Industrial Plants.)

Development of the IEEE Red Book has been an evolving process. With the publication of
IEEE Std 141-1993, the Red Book has been in print for about fifty years. Work began on the
seventh edition in 1987 with the participation of more than seventy electrical engineers from
industrial plants, consulting firms, equipment manufacturers, and academe. It was sponsored
and the final version approved by the Power Systems Design Subcommittee of the Power
Systems Engineering Committee, Industrial and Commercial Power Systems Department,
IEEE Industry Applications Society. The seventh edition was approved by the IEEE Stan-
dards Board in 1993 as an IEEE Recommended Practice. It provides pertinent information
and recommended practices for the design, construction, operation, and maintenance of elec-
tric power systems in industrial plants.

The first publication was developed in 1945 by the Committee on Industrial Power Applica-
tions of the American Institute of Electrical Engineers (AIEE). It was entitled Electric Power
Distribution for Industrial Plants and sold for $1.00 a copy. It became known by the nick-
name “Red Book” because of its red cover, and a precedent was established for the present
IEEE Color Book series, which now encompasses ten books.

The second edition was published in 1956. The committee responsible for its preparation had
become a subcommittee of the Industrial Power Systems Committee of the AIEE. This edi-
tion was identified as AIEE Number 952.

By 1964, the AIEE had become the Institute of Electrical and Electronics Engineers and the
third edition was identified as IEEE No. 141. The fourth edition was produced in 1969,
approved as an IEEE Recommended Practice, and identified as IEEE Std 141-1969. The fifth
edition, published in 1976, was IEEE Std 141-1976, and the sixth edition, published in 1986,
became an American National Standard as well as an IEEE Recommended Practice, and was
identified as ANSI/IEEE Std 141-1986.

The authors of this 1993 edition wish to acknowledge their indebtedness to the several hun-
dred engineers whose expertise and work culminated in the six previous editions. The present
stature of the Red Book would not have been achieved without their efforts.

The Red Book Working Group for the 1993 edition had the following membership:

William J. Moylan, Chair Lynn Saunders, Secretary

R. Gerald Irvine, Technical Support Lucas G. Ananian, Advisory Counsel

Chapter 1 : Overview— Dan Goldberg, Chair; Arthur Freund; R. Gerald Irvine;

C. Grant Keough; Philip Nobile; Don Zipse

Chapter 2: Systems planning— Lynn Saunders, Chair; Robert Beaker; Carl Becker;

B. L. Christen; Tom Diliberti; William Moylan; Don Pomering; Ronald Smith;
Ray Stratford; S. I. Venugopalan; Don Zipse

Chapter 3: Voltage considerations— Larry Conrad, Co-Chair; Gary Smullin, Co-Chair;
Carl Becker; Don Brereton; R. Gerald Irvine; S. I. Venugopalan

Chapter 4: Fault calculations— Walter C. Huening, Chair; Carl Becker; Richard Evans;
Shan Griffith; Mark Leyton; Conrad St. Pierre

Chapter 5: Application and coordination of protective devices— David Baker, Chair;

Jerry Baskin; Steve Goble; R. Gerald Irvine; William Moylan; Randall Schlake

Chapter 6: Surge voltage protection— Wei-Jen Lee, Chair; David Baker; Carl Becker;
Gilbert Gaibrois; Shan Griffith; William Moylan; George Walsh

Chapter 7 : Grounding— Donald W. Zipse, Chair; Robert Beaker; Kenneth Nicholson;

Jerry Brown; Daleep Mohla; Charles Dennis; Milton Robinson; S. I. Venugopalan

Chapter 8: Power factor and related considerations— William Moylan, Chair;

Carl Becker; James Harvey; Warren Lewis; Ray Stratford; George Walsh

Chapter 9: Harmonics in power systems— Ray Stratford, Chair; Larry Conrad;

Dennis Darling; William Moylan

Chapter 10: Power switching, transformation, and motor control apparatus —

Sonny Sengupta, Chair; Jerry Frank; Douglas Kanitz; R. Gerald Irvine;

Harold Miles; William Moylan

Chapter 1 1 : Instruments and meters— Larry Conrad, Chair; Valdis Basch; Harry Beckman;
Dennis Darling; James Harvey; Yoshi Held

Chapter 12: Cable systems— James Daly, Chair; Robert Beaker; Gordon Bracey;

Larry Kelly; Lynn Saunders

Chapter 13: Busways— John Schuster, Chair; Louis Capitina; Steven Flee; Robert Gustin;
Robert Ingham; James Lewis; William Moylan; Lynn Saunders

Chapter 14: Electrical conservation through energy management— Carl Becker, Chair;

Kao Chen; Joseph Eto; Dan Goldberg; R. Gerald Irvine; C. Grant Keough

Chapter 15: Industrial substations: Plant-utility interface considerations—

Tom Diliberti, Co-Chair; Ron Smith, Co-Chair; Jerry Baskin; Carl Becker;

C. W. Bierl; Larry Conrad; Joseph Dudor; Paul Gulik; Robert Hoerauf;

Daleep Mohla; William Moylan; Lynn Saunders; Michael Stark; Don Zipse

Chapter 16: Cost estimating of industrial power systems— Sonny Sengupta, Co-Chair;
Charles Dennis, Co-Chair; Robert Giese, Erling Hesla; Srimohan Jha;

William Moylan; Malcolm Woodman; Don Zipse

At the time this document was balloted, the Power Systems Design Subcommittee had the
following membership:

Stephen J. Schaffer, Chair

L. G. Ananian

S. Goble

H. C. Miles

R. J. Beaker

D. L. Goldberg

D. C. Mohla

J. H. Beall

A. P. Haggerty

W. J. Moylan

C. E. Becker

J. R. Harvey

J. R. Pfafflin

R. W. Becker

R. G. Hoerauf

C. R. Pope

G. R. J. Bracey

L. F. Hogrebe

M. D. Robinson

D. S. Brereton

R. W. Ingham

V. Saporita

R. Castenschiold

R. G. Irvine

L. F. Saunders

L. E. Conrad

D. R. Kanitz

L. H. Smith, Jr.

J. M. Daly

S. C. Kapoor

G. T. Smullin

J. Eto

C. G. Keough

T. E. Sparling

R. A. Evans

T. S. Key

S. I. Venugopalan

L. F. Flagg

C. A. LaPlatney

W. N. Vernon

J. M. Frank

S. A. Larson

P. A. Zink

E. 0. Galyon

M. Z. Lowenstein

D. W. Zipse

Others who contributed to the development of this document are as follows:

Bruce Bailey, Richard Doughty, William Kelly, Richard McFadden, Robert Simpson

Special recognition is given to Jeannette Pierce and Barbara Abitz for their contributions to
the Red Book through coordination of balloting, document preparation, and liaison with

chapter chairs.

The following persons were

on the balloting committee:

Lucas Ananian

James R. Harvey

Michael Lowenstein

Robert J. Beaker

Robert G. Hoerauf

Daleep C. Mohla

James H. Beall

Robert W. Ingham

William J. Moylan

Carl E. Becker

R. Gerald Irvine

Milton D. Robinson

Rene Castenschiold

Ed Kalkstein

Vincent Saporita

James M. Daly

Douglas R. Kanitz

Lynn F. Saunders

Richard Evans

S. C. Kapoor

Stephen J. Schaffer

Jerry M. Frank

C. Grant Keough

Lester H. Smith

Edgar 0. Galyon

Thomas S. Key

Thomas E. Sparling

Steven Goble

Steven A. Larson

S. I. Venugopalan

Daniel L. Goldberg

Wei-Jen Lee

Philip A. Zinck

Patrick A. Haggerty

Donald W. Zipse

When the IEEE Standards Board approved this standard on December 2, 1993, it had the
following membership:

Wallace S. Read, Chair

Gilles A. Baril
Jose A. Berrios de la Paz
Clyde R. Camp
Donald C. Fleckenstein
Jay Forster*

David F. Franklin
Ramiro Garcia
Donald N. Heirman

*Member Emeritus

Also included are the following nonvoting IEEE Standards Board liaisons:

Satish K. Aggarwal
James Beall
Richard B. Engelman
David E. Soffrin
Stanley I. Warshaw

Donald C. Loughry, Vice Chair
Andrew G. Salem, Secretary

Jim Isaak
Ben C. Johnson
Walter J. Karplus
Lorraine C. Kevra
E. G. “Al” Kiener
Ivor N. Knight
Joseph L. Koepfinger*
D. N. “Jim” Logothetis

Don T. Michael*
Marco W. Migliaro
L. John Rankine
Arthur K. Reilly
Ronald H. Reimer
Gary S. Robinson
Leonard L. Tripp
Donald W. Zipse

Paula M. Kelty

IEEE Standards Project Editor

Acknowledgments

We gratefully acknowledge the contributions of time, talent, and expertise the following orga-
nizations have made toward the development of this Recommended Practice:

AT&T

BICC Cables Corporation

Brown & Root, Inc. and Associated Companies

Brown & Root, Braun

Carlsons Consulting Engineers, Inc.

Clarence P. Tsung & Associates

Cleveland Electric Illuminating Company

Cooper Industries, Bussmann Division

Detroit Edison

DuPont Company

Electrical Systems Analysis (ESA)

FMC Corporation
General Electric Company
Giese & Associates
Hoechst Celanese Corporation
ICF Kaiser Engineers, Inc.

Industra Inc., Engineers & Consultants
International Transformer Corporation
John Brown E & C

Middle Tennessee State University (MTSU)

Moylan Engineering Associates, Inc.

Oak Ridge National Laboratory, MMES
Power Technology Consultants, PA.

Power Technologies, Inc.

Square D Company
Union Carbide

The University of Texas at Arlington
Westinghouse Electric Corporation
Wunderlich-Malec Engineering, Inc.

This page intentionally left blank

Contents

CLAUSE PAGE

Chapter 1

Overview 1

1 . 1 Scope and general information 1

1.2 Industrial plants 1

1.3 Industry Applications Society (IAS) 5

1.4 Professional registration 6

1.5 Professional liability 7

1.6 Codes and standards 7

1.7 Handbooks 10

1.8 Periodicals 11

1.9 Manufacturers’ Data 12

1.10 Safety 12

1.11 Maintenance 15

1.12 Design considerations 15

1.13 Estimating 19

1.14 Contracts 20

1.15 Access and loading 21

1.16 Contractor performance 21

1.17 Environmental considerations 22

1.18 Technical files 22

1.19 Electronic systems 22

1.20 Programmable logic controller 24

1.21 Bibliography 24

Chapter 2

System planning 27

2.1 Introduction 27

2.2 Definitions 27

2.3 Basic design considerations 27

2.4 Planning guide for the supply and distribution system 3 1

2.5 Power system modernization and evaluation studies/programs 56

2.6 References 58

2.7 Bibliography 59

Chapter 3

Voltage considerations 61

3.1 General 61

3.2 Voltage control in electric power systems 66

3.3 Voltage selection 78

3.4 Voltage ratings for low-voltage utilization equipment 81

CLAUSE

PAGE

3.5 Effect of voltage variations on low- voltage and medium- voltage

utilization equipment 82

3.6 Voltage drop considerations in locating the low-voltage secondary

distribution system power source 86

3.7 Improvement of voltage conditions 87

3.8 Phase-voltage unbalance in three-phase systems 89

3.9 Voltage sags and flicker 91

3.10 Harmonics 95

3.11 Calculation of voltage drops 96

3.12 References 107

3.13 Bibliography 108

Chapter 4

Short-circuit current calculations 109

4.1 Introduction 109

4.2 Sources of fault current 109

4.3 Fundamentals of short-circuit current calculations 112

4.4 Restraints of simplified calculations 115

4.5 Detailed procedure 124

4.6 Example of short-circuit current calculation for a power system with

several voltage levels 138

4.7 Example of short-circuit current calculation for a low-voltage system

(under 1000 V) 158

4.8 Calculation of short-circuit currents for dc systems 170

4.9 References 170

4.10 Bibliography 171

Annex 4A

Typical impedance data for short-circuit studies 173

Chapter 5

Application and coordination of protective devices 185

5.1 Purpose 185

5.2 Analysis of system behavior and protection needs 187

5.3 Protective devices and their applications 192

5.4 Performance limitations 222

5.5 Principles of protective relay application [38], [40], [50] 223

5.6 Protection requirements 238

5.7 Use and interpretation of time-current coordination curves 250

5.8 Specific examples — applying the fundamentals 260

5.9 Acceptance testing (commissioning), maintenance, and field testing 281

5.10 Bibliography 304

xii

CLAUSE

PAGE

Chapter 6

Surge voltage protection 311

6. 1 Nature of the problem 3 1 1

6.2 Traveling-wave behavior 315

6.3 Insulation voltage withstand characteristics 322

6.4 Arrester characteristics and ratings 330

6.5 Arrester selection 336

6.6 Selection of arrester class 338

6.7 Application concepts 340

6.8 References 355

6.9 Bibliography 357

Chapter 7

Grounding 363

7.1 Introduction 363

7.2 System grounding 363

7.3 Equipment grounding 370

7.4 Static and lightning protection grounding 375

7.5 Connection to earth 379

7.6 Ground resistance measurement 383

7.7 References 389

7.8 Bibliography 389

Chapter 8

Power factor and related considerations 393

8.1 General scope 393

8.2 Current and power flow fundamentals 394

8.3 Benefits of power-factor improvement 397

8.4 Typical plant power factor 402

8.5 Instruments and measurements for power-factor studies 404

8.6 Techniques to improve the power factor 405

8.7 Calculation methods for improving power factor 410

8.8 Location of reactive power supply 41 1

8.9 Capacitors with induction motors 412

8.10 Capacitor standards and operating characteristics 422

8.11 Controls for switched capacitors 425

8.12 Transients and capacitor switching 427

8.13 Protection of capacitors and capacitor banks 435

8.14 Resonance and harmonics 437

8.15 Inspection and field testing of power capacitors 438

8.16 References 440

8.17 B ibliography 442

xiii

CLAUSE

PAGE

Chapter 9

Harmonics in power systems 443

9. 1 Introduction 443

9.2 Importance of understanding effects of harmonics 443

9.3 History of harmonic problems and solutions 444

9.4 Definition and sources of harmonic currents and voltages 445

9.5 Characteristics of harmonics 447

9.6 Static power converter theory 449

9.7 System response characteristics 455

9.8 Effects of harmonics 458

9.9 Harmonic analysis 466

9.10 Mitigation techniques 467

9.11 Industry standards 471

9.12 Bibliography 473

Chapter 10

Power switching, transformation, and motor control apparatus 475

10.1 Introduction 475

10.2 Switching apparatus for power circuits 478

10.3 Switchgear 492

10.4 Transformers 503

10.5 Unit substations 519

10.6 Motor control equipment 521

10.7 Adjustable speed drives 529

10.8 Bibliography 532

Chapter 1 1

Instruments and meters 537

11.1 Introduction 537

1 1.2 Basic objectives 540

11.3 Switchboard and panel instruments 540

1 1.4 Portable instruments 542

1 1.5 Recording instruments 543

1 1.6 Miscellaneous instruments 544

11.7 Meters 545

11.8 Auxiliary devices 549

1 1.9 Typical installations 551

11.10 Bibliography 552

Chapter 12

Cable systems 553

12.1 Introduction 553

xiv

CLAUSE PAGE

12.2 Cable construction 554

12.3 Cable outer finishes 566

12.4 Cable ratings 570

12.5 Installation 579

12.6 Connectors 586

12.7 Terminations 592

12.8 Splicing devices and techniques 601

12.9 Grounding of cable systems 605

12.10 Protection from transient overvoltage 606

12.11 Testing 607

12.12 Locating cable faults 613

12.13 Cable specification 617

12.14 References 617

12.15 Bibliography 619

Chapter 13

Bus ways 621

13.1 Origin 621

13.2 Busway construction 621

13.3 Feeder bus way 623

13.4 Plug-in busway 624

13.5 Lighting busway 626

13.6 Trolleybusway 627

13.7 Standards 627

13.8 Selection and application of busways 628

13.9 Layout 634

13.10 Installation 635

13.11 Field testing 637

13.12 Busways over 600 V (metal-enclosed bus) 637

13.13 References 639

Chapter 14

Electrical conservation through energy management 641

14.1 Introduction 641

14.2 Finding energy conservation opportunities 642

14.3 The energy management process 643

14.4 Calculating energy savings 646

14.5 Load management 653

14.6 Efficiencies of electrical equipment 655

14.7 Metering 658

14.8 Lighting 660

14.9 Cogeneration 669

14.10 Peak shaving 670

14. 1 1 Summary 670

14.12 Bibliography 672

CLAUSE

PAGE

Chapter 15

Industrial substations: plant-utility interface considerations 675

15.1 Introduction 675

15.2 Planning stage 678

15.3 Design stage 689

15.4 Construction stage 697

15.5 Operating stage 699

15.6 Bibliography 700

Chapter 16

Cost estimating of industrial power systems 703

16.1 Introduction 703

16.2 Information required 703

16.3 Factors to be considered 704

16.4 Preparing the cost estimate 704

16.5 Classes of estimates 704

16.6 Equipment and material costs 705

16.7 installation costs 705

16.8 Other costs 706

16.9 Example 706

16.10 Bibliography 707

Annex 16A

Selected sources for cost-estimating information 719

Annex A

Power system device function numbers 721

INDEX 729

xvi

IEEE Recommended Practice for Electric
Power Distribution for Industrial Plants

Chapter 1
Overview

1.1 Scope and general information

This publication provides a recommended practice for the electrical design of industrial facil-
ities. It is likely to be of greatest value to the power-oriented engineer with limited industrial
plant experience. It can also be an aid to all engineers responsible for the electrical design of
industrial facilities. However, it is not intended as a replacement for the many excellent engi-
neering texts and handbooks commonly in use, nor is it detailed enough to be a design man-
ual. It should be considered a guide and general reference on electrical design for industrial
plants and buildings.

Tables, charts, and other information that have been extracted from codes, standards, and
other technical literature are included in this publication. Their inclusion is for illustrative
purposes; where technical accuracy is important, the latest version of the referenced docu-
ment should be consulted to assure use of complete, up-to-date, and accurate information.

It is important to establish, at the outset, the terms describing voltage classifications. Table
1-1, adapted from IEEE Std 100-1992 [B5], 1 indicates these voltage levels. The National
Electrical Code, described in 1.5.1, uses the term over 600 volts generally to refer to what is
known as high voltage. Many IEEE Power Engineering Society (PES) standards use the term
high voltage to refer to any voltage higher than 1000. All nominal voltages are expressed in
terms of root-mean-square (rms). For a detailed explanation of voltage terms, see Chapter 3.
ANSI C84. 1-1977 [Bl] lists voltage class designations applicable to industrial and commer-
cial buildings where medium voltage extends from 1000 V to 69 kV nominal.

1.2 Industrial plants

The term industrial plants, as used in this chapter, refers to industrial plants, buildings, and
complexes where manufacturing, industrial production, research, and development are per-
formed. It does not include commercial buildings, such as institutional, governmental, public,
health-related office buildings, nor apartment and residential buildings.

If commercial buildings are included in industrial complexes, then the use of IEEE Std 241-
1990 (the Gray Book) would be appropriate for these specific buildings. If medical facilities

'The numbers in brackets preceded by the letter B correspond to those of the bibliography in 1.21.

IEEE

Std 141-1993 CHAPTER 1

Table 1-1 — Voltage classes

Nominal System Voltage

' 120 )

<1
> >-
£ M
o

'3 O

i §

o >
*6

■3 2
■= Q
5 uj

' t-
0 5 «/>

$ >*
OO t/5

’T 1 u
- -1 O

03 >

If.

T~T-

EHV cq
EHV g
EHV O

THREE

WIRE

Four

hire

Maximum

Voltage

Single-Pi

ase Systems

127

1201240

127/254

Tltree-Phase Systems

208Y/120

220Y/127

(240)

240/120

245/127

480

480Y/277

508Y/293

(600)

635

(2400)

2540

4160

4160Y/2400

4400Y/2540

(4800)

5080

(6900)

7260

(8320Y/4800)

8800Y/5080

(12000Y/6930)

12700Y/7330

12470Y/7200

13200Y/7620

1 3200Y/7620

13970Y/8070

13800

(1 3800Y/7970)

14520Y/8380

(20780Y/12000)

22000Y/ 2700

(22860Y/13200)

24200Y/13970

(23000)

24340

24940 Y/ 14400

26400Y/15240

(34S00)

34500/19920

365I0Y/21080

(46 kV)

48.3 kV

69 kV

72.5 kV

115 kV

121 kV

138 kV

145 kV

(161 kV)

169 kV

230 kV

242 kV

345 kV

362 kV

500 kV

550 kV

765 kV

800 kV

1 100 kV

1200 kV

are included, IEEE Std 602-1986 (the White Book), should be consulted. (See 1.3.2 for a
complete listing of the IEEE Color Books.)

The specific use of the facility or area in question, rather than the overall nature of the facility,
determines its electrical design category. While industrial plants are primarily machine- and

OVERVIEW

IEEE
Std 141-1993

production-oriented; commercial, residential, and institutional buildings are primarily
people- and public-oriented. The fundamental objective of industrial plant design is to pro-
vide a safe, energy-efficient, and attractive environment for the manufacturing, research,
development, and handling of industrial products. The electrical design must satisfy these
criteria if it is to be successful.

Today’s industrial plants, because of their increasing size, more complex processes, and
newer technologies, have become more and more dependent upon adequate and reliable elec-
trical systems. The complex nature of modern industrial plants can be better understood by
examining the systems, equipment, and facilities listed in 1.2.1.

1.2.1 System requirements for industrial plants

The systems and equipment that must be provided in order to satisfy functional requirements
will vary with the type of facility, but will generally include some, or all, of the following;

— Building electric service;

— Power distribution systems for manufacturing and process equipment. Plant distribu-
tion system for “house loads”;

— Power outlet systems for movable equipment: receptacles, trolley systems, plug-in
and trolley-busways, festoon-cable systems, and heavy portable cord systems;

— Process control systems, including computer-based equipment such as programmable
controllers, robotic equipment, and special-purpose controllers of the relay or solid-
state types. On-line, real-time computer systems;

— Materials handling systems: cranes, hoists, distribution systems, automated systems
that identify and distribute products (as well as update production data bases);

— Lighting: interior and exterior, security and decorative, task and general lighting;

— Communications: telephone, facsimile, telegraph, satellite link, building-to-building
communications (including microwave), computer link, radio, closed-circuit tele-
vision. code call, public-address paging, fiber-optic and electronic intercommunica-
tion. pneumatic tube, medical alert, emergency and medical call, and a variety of
other signal systems;

— Fire alarm systems: fire pumps and sprinklers, smoke and fire detection, alarm sys-
tems, and emergency public-address systems. Emergency alarm systems relating to
dangerous process control failure conditions;

— Transportation: passenger and freight elevators, moving stairways, and dumbwaiters;

— Space-conditioning: heating, ventilation, and air-conditioning. Ambient temperature
and dew-point controls relating to the specific manufacturing processes;

— Sanitation: garbage and rubbish storage, recycling, compaction and removal, docu-
ment disposal equipment, incinerators, and sewage handling. Handling and storage of
environmentally hazardous and sensitive waste materials;

— Environmental containment of materials classified as hazardous to the environment,
including maintenance of containment systems (e.g., pressure, temperature);

— Plumbing: hot and cold water systems and water-treatment facilities;

— Security watchmen, burglar alarms, electronic access systems, and closed-circuit sur-
veillance television;

IEEE

Std 141-1993

CHAPTER 1

— Business machines: typewriters, computers, calculating machines, reproduction
machines, and word processors;

— Refrigeration equipment;

— Compressed air, vacuum systems, process gas storage and handling systems;

— “Clean or secure areas” for isolation against contaminants and/or electromagnetic and
radio-frequency interference (EMI/RFI);

— Food handling, dining and cafeteria, and food preparation facilities;

— Maintenance facilities;

— Lightning protection;

— Automated facility control systems;

— Showrooms, training areas;

— Medical facilities;

— Employee rest and recreational areas;

— In-plant generation, cogeneration, and total energy provisions. Legally required and
optional standby/emergency power and peak-shaving systems;

— Signing, signaling, and traffic control systems. Parking control systems, including
automated parking systems.

1.2.2 Electrical design elements

In spite of the wide variety of industrial buildings, some electrical design elements are com-
mon to all. These elements, listed below, will be discussed generally in this chapter and in
detail in the remaining chapters of this Recommended Practice. The principal design ele-
ments considered in the design of the power, lighting, and auxiliary systems include the
following:

— Magnitudes, quality, characteristics, demand, and coincidence or diversity of loads
and load factors;

— Service, distribution, and utilization voltages and voltage regulation;

— Flexibility and provisions for expansion;

— Reliability, continuity;

— Safety of personnel and property;

— Initial and maintained cost (“own-and-operate” costs);

— Operation and maintenance;

— Fault current and system coordination;

— Power sources;

— Distribution systems;

— Legally required and optional standby /emergency power systems;

— Energy conservation, demand, and control;

— Conformity with regulatory requirements;

— Special requirements associated with industrial processes;

— Special requirements of the site related to seismic requirements [B5], altitude, sound
levels, security, exposure to physical elements, fire hazards [B6], and hazardous loca-
tions. Power conditioning and uninterruptible power supplies (UPS) systems.

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IEEE
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1.3 Industry Applications Society (IAS)

The IEEE is divided into 37 societies and technical councils that specialize in various techni-
cal areas of electrical and electronics engineering. Each group or society conducts meetings
and publishes papers on developments within its specialized area.

The IAS currently encompasses 20 technical committees that cover the specific aspects of
electrical engineering listed in 1.3.1, below. Papers of interest to electrical engineers and
designers involved in the fields covered by the IEEE Red Book are, for the most part, con-
tained in the Transactions of the IAS.

1.3.1 Committees within the IAS

The IAS is concerned with the power and control aspects of industrial plant and commercial
buildings. To that end, in addition to the more general Power Systems Engineering and Power
Systems Protection Committees within the Industrial and Commercial Power Systems
Department, the following committees are involved with specific types of industries:

— Appliance Industry

— Cement Industry

— Electric Machines

— Electrostatic Processes

— Glass Industry

— Industrial Drives

— Industrial Automation and Control

— Industrial Power Converter

— Marine Transportation

— Metal Industry

— Mining Industry

— Petroleum and Chemical Industry

— Power Electronics Devices and Components

— Pulp and Paper Industry

— Rubber and Plastics Industry

— Rural Electric Power

— Textile, Fiber, and Film Industry

The Production and Application of Light (PALC), Power Systems Engineering, Power
Systems Protection, Codes and Standards, Energy Systems, and Mining Safety Standards
Committees of the IAS are involved with industrial power activities, and some publish mate-
rial applicable to many types of industrial facilities.

All of the committees mentioned develop standards and articles for conference records and
for the IAS Transactions. These publications deal with specialized electrical aspects of manu-
facturing and with electrical power and control systems for specific industries in greater
detail than is possible in the Red Book.

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1.3.2 The IEEE Color Books

The IEEE Red Book is one of a series of standards that are published by IEEE and are known
as the IEEE Color Books. These standards are prepared by the Industrial and Commercial
Power Systems Department of the IEEE Industry Applications Society. They are as follows:

— IEEE Std 141-1993, IEEE Recommended Practice for Electric Power Distribution for
Industrial Plants (IEEE Red Book).

— IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and
Commercial Power Systems (IEEE Green Book).

— IEEE Std 241-1990, IEEE Recommended Practice for Power Systems in Commercial
Buildings (IEEE Gray Book).

— IEEE Std 242-1986, IEEE Recommended Practice for Protection and Coordination of
Industrial and Commercial Power Systems (IEEE Buff Book).

— IEEE Std 399-1990, IEEE Recommended Practice for Industrial and Commercial
Power System Analysis (IEEE Brown Book).

— IEEE Std 446-1987, IEEE Recommended Practice for Emergency and Standby Power
Systems for Industrial and Commercial Applications (IEEE Orange Book).

— IEEE Std 493-1990, IEEE Recommended Practice for the Design of Reliable Indus-
trial and Commercial Power Systems (IEEE Gold Book).

— IEEE Std 602-1986, IEEE Recommended Practice for Electric Systems in Health
Care Facilities (IEEE White Book).

— IEEE Std 739-1984, IEEE Recommended Practice for Energy Conservation and Cost-
Effective Planning in Industrial Facilities (IEEE Bronze Book).

— IEEE Std 1100-1992, IEEE Recommended Practice for Powering and Grounding
Sensitive Electronic Equipment (IEEE Emerald Book).

1.4 Professional registration

Most regulatory agencies require that design for public and other buildings be prepared under
the jurisdiction of state-licensed professional architects or engineers. Information on such
registration may be obtained from the appropriate state agency or from the local chapter of
the National Society of Professional Engineers.

To facilitate obtaining registration in different states under the reciprocity rule, a National
Professional Certificate is issued by the Records Department of the National Council of Engi-
neering Examiners to engineers who obtained their home-state license by examination. All
engineering graduates are encouraged to start on the path to full registration by taking the
engineer-in-training examination as soon after graduation as possible. The final written exam-
ination in the field of specialization is usually conducted after four years of progressive pro-
fessional experience.

2 P.O. Box 1686, Clemson, SC 29633-1686.

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IEEE
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1.5 Professional liability

Recent court and regulatory decisions have held the engineer and designer liable for situa-
tions that have been interpreted as malpractice. These decisions have involved safety, envi-
ronmental concerns, specification and purchasing practice, and related items. Claims for
accidents, purportedly resulting from poor design or operating practice (e.g., too low lighting
levels), have resulted in awards against engineering firms and design staff. Practicing engi-
neers are encouraged to determine policies for handling such claims and to evaluate the need
for separate professional liability insurance.

1.6 Codes and standards

1.6.1 National Electrical Code

The electrical wiring requirements of the National Electrical Code (NEC) (ANSI/NFPA
70-1993 [B 1 ]), are vitally important guidelines for electrical engineers. The NEC is revised
every three years. It is published by and available from the National Fire Protection Associa-
tion (NFPA). 3 It is also available from the American National Standards Institute (ANSI) 4
and from each State’s Board of Fire Underwriters (usually located in the State Capital). It
does not represent a design specification but does identify minimum requirements for the safe
installation and utilization of electricity. It is strongly recommended that the introduction to
the NEC, Article 90, covering purpose and scope, be carefully reviewed.

The NFPA Handbook of the National Electrical Code, No. 70HB, sponsored by the NFPA,
contains the complete NEC text plus explanations. This book is edited to correspond with
each edition of the NEC. McGraw Hill’s Handbook of the National Electrical Code, and
other handbooks, provide explanations and clarification of the NEC requirements.

Each municipality or jurisdiction that elects to use the NEC must enact it into law or regula-
tion. The date of enactment may be several years later than issuance of the code, in which
event, the effective code may not be the latest edition. It is important to discuss this with the
inspection or enforcing authority. Certain requirements of the latest edition of the Code may
be interpreted as acceptable by the authority.

1.6.2 Other NFPA standards

The NFPA publishes the following related documents containing requirements on electrical
equipment and systems:

— NFPA HFPE and Society of Fire Protection Engineers’ SFPE Handbook of Fire Pro-
tection Engineering

— NFPA 10 1H, Life Safety Code Handbook

— NFPA 20, Centrifugal Fire Pumps, 1987

3 Batterymarch Park. Quincy, MA 02269.

4 1 1 West 42nd Street, 1 3th Floor, New York, NY 10036.

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— NFPA 70B, Electrical Equipment Maintenance, 1990

— NFPA 70E, Electrical Safety Requirements for Employee Workplaces, 1988

— NFPA 72, National Fire Alarm Code

— NFPA 75, Protection of Electronic Computer/Data Processing Equipment, 1992

— NFPA 77, Static Electricity, 1993

— NFPA 78, Lightning Protection Code, 1992

— NFPA 79, Electrical Standard for Industrial Machinery, 1991

— NFPA 92A, Smoke Control Systems, 1993

— NFPA 99, Health Care Facilities, 1990: Chapter 8: Essential Electrical Systems for
Health Care Facilities; Appendix E: The Safe Use of High Frequency Electricity in
Health Care Facilities

— NFPA 101, Life Safety Code, 1991

— NFPA 1 10, Emergency and Standby Power Systems, 1993

— NFPA 130, Fixed Guideway Transit Systems, 1990

1.6.3 Local, state, and federal codes and regulations

While most municipalities, counties, and states use the NEC (either with or without modifica-
tions), some have their own codes. In most instances, the NEC is adopted by local ordinance
as part of the building code. Deviations from the NEC may be listed as addenda. It is impor-
tant to note that only the code adopted by ordinance as of a certain date is official, and that
governmental bodies may delay adopting the latest code. Federal rulings may require use of
the latest NEC rulings, regardless of local rulings, so that reference to the enforcing agencies
for interpretation on this point may be necessary.

Some city and state codes are almost as extensive as the NEC. It is generally accepted that in
the case of conflict, the more stringent or severe interpretation applies. Generally the entity
responsible for enforcing (enforcing authority) the code has the power to interpret it. Failure
to comply with NEC or local code provisions, where required, can affect the owner’s ability
to obtain a certificate of occupancy, may have a negative effect on insurability, and may sub-
ject the owner to legal penalty.

Legislation by the U.S. federal government has had the effect of giving standards, such as
certain American National Standards Institute (ANSI) standards, the impact of law. The
Occupational Safety and Health Act, administered by the U.S. Department of Labor, permits
federal enforcement of codes and standards. The Occupational Safety and Health Administra-
tion (OSHA) adopted the 1971 NEC for new electrical installations and also for major
replacements, modifications, or repairs installed after March 5, 1972. A few articles and sec-
tions of the NEC have been deemed by OSHA to apply retroactively. The NFPA created an
NFPA 70E (Electrical Requirements for Employee Workplaces) Committee to prepare a con-

OVERVIEW

IEEE
Std 141-1993

sensus standard for possible use by OSHA in developing their standards. Major portions of
NFPA 70E have been included in OSHA regulations.

OSHA requirements for electrical systems are covered in 29 CFR Part 1910 of the Federal
Register. 5

The U.S. National Institute of Occupational Safety and Health (NIOSH) publishes “Electrical
Alerts” to warn of unsafe practices or hazardous electrical equipment. 6

The U.S. Department of Energy, in Building Energy Performance Standards, has advanced
energy conservation standards. A number of states have enacted energy conservation regula-
tions. These include ASHRAE/IES legislation embodying various energy conservation stan-
dards, such as ASHRAE/IES 90. IP, Energy Efficient Design of New Buildings Except Low
Rise Residential Buildings. These establish energy or power budgets that materially affect
architectural, mechanical, and electrical designs.

1.6.4 Standards and Recommended Practices

A number of organizations, in addition to the NFPA, publish documents that affect electrical
design. Adherence to these documents can be written into design specifications.

The American National Standards Institute (ANSI) coordinates the review of proposed stan-
dards among all interested affiliated societies and organizations to assure a consensus
approval. It is, in effect, a clearing house for technical standards. Not all standards are ANSI-
approved. Underwriters Laboratories, Inc. (UL), and other independent testing laboratories
may be approved by an appropriate jurisdictional authority (e.g., OSHA) to investigate mate-
rials and products, including appliances and equipment. Tests may be performed to their own
or to another agency’s standards and a product may be “listed” or “labeled.” The UL pub-
lishes an Electrical Construction Materials Directory, an Electrical Appliance and Utilization
Equipment Directory, a Hazardous Location Equipment Directory, and other directories. It
should be noted that other testing laboratories (where approved) and governmental inspection
agencies may maintain additional lists of approved or acceptable equipment; the approval
must be for the jurisdiction where the work is to be performed. The Electrification Council
(TEC), 7 representative of investor-owned utilities, publishes several informative handbooks,
such as the Industrial and Commercial Power Distribution Handbook and the Industrial and
Commercial Lighting Handbook, as well as an energy analysis computer program, called
AXCESS, for forecasting electricity consumption and costs in existing and new buildings.

The National Electrical Manufacturers Associations (NEMA) 8 represents equipment manu-
facturers. Their publications serve to standardize certain design features of electrical equip-
ment and provide testing and operating standards for electrical equipment. Some NEMA

5 The Federal Register is available from the Superintendent of Documents, U.S. Government Printing Office, Wash-
ington, DC 20402, (202) 783-3238 on a subscription or individual copy basis.

6 Copies of the bulletin are available from NIOSH Publications Dissemination, 4676 Columbia Parkway, Cincinnati,
OH 45226.

7 1 1 1 1 1 9th Street. NW, Washington, DC 20036.

8 2 10 1 L Street, NW, Suite 300, Washington, DC 20037.

IEEE

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standards contain important application information for equipment such as motors and circuit
breakers.

The IEEE publishes several hundred electrical standards relating to safety, measurements,
equipment testing, application, maintenance, and environmental protection. Also published
are standards on more general subjects, such as the use of graphic symbols and letter
symbols. The IEEE Standard Dictionary of Electrical and Electronics Terms is of particular
importance.

The Electric Generating Systems Association (EGSA) 9 publishes performance standards for
emergency, standby, and cogeneration equipment.

The Intelligent Buildings Institute (IBI) 10 publishes standards on the essential elements of
“high-tech” buildings.

The Edison Electric Institute (EEI) 11 publishes case studies of electrically space-conditioned
buildings as well as other informative pamphlets.

The International Electrotechnical Commission (IEC) is an electrical and electronic standards
generating body with a multinational membership. The IEEE is a member of the U.S.
National Committee of the IEC.

1.7 Handbooks

The following handbooks have, over the years, established reputations in the electrical field.
This list is not intended to be all-inclusive; other excellent references are available but are not
listed here because of space limitations.

— Fink, D. G. and Beaty, H. W., Standard Handbook for Electrical Engineers, 12th
edition, McGraw-Hill, 12 1987. Virtually the entire field of electrical engineering is
treated, including equipment and systems design.

— Croft, T., Carr, C. C., and Watt, J. H., American Electricians Handbook, 1 1th edition.
New York, McGraw-Hill, 1987. The practical aspects of equipment, construction, and
installation are covered.

— Lighting Handbook, Illuminating Engineering Society (IES). This handbook is in
two volumes (Applications, 1987; Reference, 1984). All aspects of lighting, including
visual tasks, recommended lighting levels, lighting calculations, and lighting design
are included in extensive detail in this comprehensive text.

9 P.O. Box 9257, Coral Springs. FL 33065.

10 2101 L Street, NW, Washington, DC 20037.

11 1 1 1 1 19th Street, NW, Washington, DC 20036.
12 1221 Avenue of the Americas, New York. NY 10020.
13 345 East 47th Street, New York, NY 10017.

OVERVIEW

IEEE
Std 141-1993

— Electrical Transmission and Distribution Reference Book, Westinghouse Electric Cor-
poration. 14 1964. All aspects of transmission, distribution, performance, and protec-
tion are included in detail.

— Applied Protective Relaying, Westinghouse Electric Corporation, 1976. The applica-
tion of protective relaying to customer-utility interconnections, protection of high-
voltage motors, transformers, and cable are covered in detail.

— ASHRAE Handbook, American Society of Heating, Refrigerating, and Air-Condition-
ing Engineers (ASHRAE). 15 This series of reference books in four volumes, which
are periodically updated, details the electrical and mechanical aspects of space condi-
tioning and refrigeration.

— Motor Applications and Maintenance Handbook, 2nd edition, Smeaton, R. S., editor,
McGraw-Hill, 1987. Contains extensive, detailed coverage of motor load data and
motor characteristics for coordination of electric motors with machine mechanical
characteristics.

— Industrial Power Systems Handbook, Beeman, D. L., editor, McGraw-Hill, 1955. A
text on electrical design with emphasis on equipment, including that applicable to
commercial buildings.

— Electrical Maintenance Hints, Westinghouse Electric Corporation. 1984. The preven-
tive maintenance procedures for all types of electrical equipment and the rehabilita-
tion of damaged apparatus are discussed and illustrated.

— Lighting Handbook, Philips Lighting Company, 16 1984. The application of various
light sources, fixtures, and ballasts to interior and exterior commercial, industrial,
sports, and roadway lighting projects.

— Underground Systems Reference Book, Edison Electric Institute, 1957. The principles
of underground construction and detailed design of vault installations, cable systems,
and related power systems are fully illustrated; cable splicing design parameters are
thoroughly covered.

— Switchgear and Control Handbook, 2nd edition, Smeaton, R. S., editor, McGraw Hill,
1987. Concise, reliable guide to important facets of switchgear and control design,
safety, application, and maintenance, including high- and low- voltage starters, circuit
breakers, and fuses.

— Handbook of Practical Electrical Design, J. M. McPartland, Editor, McGraw Hill,
1984.

A few of the older texts may no longer be available for purchase but are available in most pro-
fessional offices and libraries.

1.8 Periodicals

Spectrum, the monthly magazine of the IEEE that is circulated to all of its members, contains
articles that cover current developments in all areas of electrical and electronics engineering.
It contains references to IEEE books; technical publication reviews; technical meetings and

14 Printing Division, Forbes Road, Trafford, PA 15085.

15 1 79 1 Tullie Circle, NE, Atlanta, GA 30329.

16 200 Franklin Square Drive, P.O. Box 6800, Somerset, NJ 08875-6800.

IEEE

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conferences; IEEE group, society, and committee activities; abstracts of papers and publica-
tions of the IEEE and other organizations; and other material essential to the professional
advancement of the electrical engineer.

The Transactions of the IAS of the IEEE are directly useful to industrial facility electrical
engineers. Some other well-known periodicals follow:

— ASHRAE Journal , American Society of Heating, Refrigerating and Air-Conditioning
Engineers

1 7

— Electrical Construction and Maintenance (EC&M). Intertec Publishing Corp.

— Fire Journal, National Fire Protection Association (NFPA)

— IAEI News, International Association of Electrical Inspectors

— Lighting Design and Application (LD&A), Illuminating Engineering Society

i o

— Electrical Systems Design, Andrews Communications, Inc.

— Engineering Times, National Society of Professional Engineers (NSPE) 19

— Consulting-Specifying Engineer, Cahners Publishing Co.

— Plant Engineering, Cahners Publishing Co.

1.9 Manufacturers’ Data

The electrical industry, through its associations and individual manufacturers of electrical
equipment, issues many technical bulletins, data books, and magazines. While some of this
information is difficult to obtain, copies should be available to each major design unit. The
advertising sections of electrical magazines contain excellent material, usually well illus-
trated and presented in a clear and readable form, concerning the construction and application
of equipment. Such literature may be promotional; it may present the advertiser’s equipment
or methods in a best light and should be carefully evaluated. Manufacturers’ catalogs are a
valuable source of equipment information. Some manufacturers’ complete catalogs are quite
extensive, covering several volumes. However, these companies may issue condensed cata-
logs for general use. A few manufacturers publish regularly scheduled magazines containing
news of new products and actual applications. Data sheets referring to specific items are
almost always available from marketing offices.

1.10 Safety

Safety of life and preservation of property are two of the most important factors in the design
of the electrical system. In industrial facilities, continuity of the production and related pro-
cesses may be critical. The loss of production may result in financial loss because of idle time
for employees and machinery, the inability to meet schedules for deliveries, and materials
handling and spoilage of materials in process. Safety considerations may be aggravated by

17 1221 Avenue of the Americas, New York. NY 10020.
ls 5123 West Chester Pike, P.O. Box 556, Edgemont, PA 19028.

19 1420 King Street, Alexandria, VA 22314.

20 Cahners Plaza, 1350 East Touhy Avenue, P.O. Box. 508, Des Plaines, IL 60017-8800.

OVERVIEW

IEEE
Std 141-1993

the sheer amount of complex electrical connections and the nature of the machinery. The poor
quality or failure of electric power to equipment can cause, in some industrial processes, con-
ditions that can result in hazardous situations. Electromagnetic interference (EMI) can cause
safety controls to fail in marginally designed systems.

Various codes provide rules and regulations as minimum safeguards of life and property. The
electrical design engineer may often provide greater safeguards than outlined in the codes,
according to his or her best judgment, while also giving consideration to utilization and
economics.

Personnel safety may be divided into two categories:

— Safety for maintenance and operating personnel;

— Safety for others, including visitors, production staff, and non-production staff in the
vicinity.

Safety for maintenance and operating personnel is achieved through proper design and selec-
tion of equipment with regard to enclosures, key-interlocking, circuit breaker and fuse inter-
rupting capacity, the use of high-speed fault detection and circuit-opening devices,
clearances, grounding methods, and identification of equipment.

Safety for others requires that all circuit-making-and-breaking equipment, as well as other
electrical apparatus, be isolated from casual contact. This is achieved by using dead-front
equipment, locked rooms and enclosures, proper grounding, limiting of fault levels, installa-
tion of barriers and other isolation (including special ventilating grilles), proper clearances,
adequate insulation, and similar provisions outlined in this standard.

The U.S. Department of Labor has issued the “OSHA Rule on Lockout/Tagout” published in
the Federal Register (53 FR 1546, January 2, 1990), which is concerned with procedures for
assuring the safety of workers directly involved in working with or near energized conductors
or conductors which, if energized, could be hazardous.

The National Electrical Safety Code (NESC) (Accredited Standards Committee C2-1993) is
available from the IEEE. It covers basic provisions for safeguarding from hazards arising
from the installation operation or maintenance of a) conductors in electric supply stations,
and b) overhead and underground electric supply and communication lines. It also covers
work rules for construction, maintenance, and operation of electric supply and communica-
tion equipment. Part 4 deals specifically with safe working methods.

Circuit protection is a fundamental safety requirement of all electrical systems. Adequate
interrupting capacities are required in services, feeders, and branch circuits. Selective, auto-
matic isolation of faulted circuits represents good engineering. Fault protection, covered in
Chapters 5 and 6, should be designed and coordinated throughout the system. Physical pro-
tection of equipment from damage or tampering, and exposure of unprotected equipment to
electrical, chemical, and mechanical damage is necessary.

IEEE

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1.10.1 Appliances and equipment

Improperly applied or inferior materials can cause electrical failures. The use of appliances
and equipment listed by UL, OSHA, or other approved laboratories is recommended. The
Association of Home Appliance Manufacturers (AHAM) and the Air-Conditioning and
Refrigeration Institute (ARI) specify the manufacture, testing, and application of many
common appliances and equipment. High-voltage equipment and power cable is manufac-
tured in accordance with UL, NEMA, ANSI, and IEEE standards. Engineers should make
sure that the equipment they specify and accept conforms to these standards. Properly pre-
pared specifications can prevent the purchase of inferior or unsuitable equipment. The lowest
initial purchase price may not result in the lowest cost after taking into consideration operat-
ing, maintenance, and owning costs. Value engineering is an organized approach to the iden-
tification of unnecessary costs, which utilizes such methods as life-cycle cost analysis, and
related techniques.

1.10.2 Operational considerations

When design engineers lay out equipment rooms and locate electrical equipment, they cannot
always avoid having some areas accessible to unqualified persons. Dead-front construction
should be utilized whenever practical. Where dead-front construction is not available, as may
be the case for certain industrial configurations or in existing installations, all exposed electri-
cal equipment should be placed behind locked doors or gates or otherwise suitably guarded.
Proper barricading, signing, and guarding should be installed and maintained on energized
systems or around machinery that could be hazardous, or is located in occupied areas. Work
rules, especially in areas of medium or high voltage, should be established.

Work on energized power systems or equipment should be permitted only where qualified
staff is available to perform such work and only if it is essential. This is foremost a matter of
safety, but is also required to prevent damage to equipment. A serious cause of failure, attrib-
utable to human error, is unintentional grounding or phase-to-phase short circuiting of equip-
ment that is being worked on. By careful design, such as proper spacing and barriers, and by
enforcement of published work-safety rules, the designer can minimize this hazard. Unantici-
pated backfeeds through control circuitry, from capacitors, instrument transformers, or test
equipment, presents a danger to the worker.

Protective devices, such as ground-fault relays and ground-fault detectors (for high-resistance
or ungrounded systems), will minimize damage from electrical failures. Electrical fire and
smoke can cause maintenance staff to disconnect all electric power, even if there is not direct
danger to the occupants. Electrical failures that involve smoke and noise, even though occur-
ring in unoccupied areas, may cause confusion to the working population. Nuisance tripping,
which may interrupt industrial processes, can be minimized by careful design and selection
of protective equipment.

21 20 North Wacker Drive, Chicago. IL 60606.

“815 North Fort Myer Drive, Arlington, VA 22209.

OVERVIEW

IEEE
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1.11 Maintenance

Maintenance is essential to proper operation. The installation should be so designed that
maintenance can be performed with normally available maintenance personnel (either in-
house or contract). Design details should provide proper space, accessibility, and working
conditions so that the systems can be maintained without difficulty and excessive cost.

Generally, the external systems are operated and maintained by the electrical utility, though at
times they are a part of the plant distribution system. Where continuity of service is essential,
suitable transfer equipment and alternate sources should be provided. Such equipment is
needed to maintain minimum lighting requirements for passageways, stairways, and critical
areas as well as to supply power to critical loads. These systems usually include automatic or
manual equipment for transferring loads on loss of normal supply power or for putting bat-
tery or generator-fed equipment into service.

Annual or other periodic shut-down of electrical equipment may be necessary to perform
required electrical maintenance. Protective relaying systems, circuit breakers, switches, trans-
formers, and other equipment should be tested on appropriate schedules. Proper system
design can facilitate this work.

1.12 Design considerations

Electrical equipment usually occupies a relatively small percentage of the total plant space
and, in design, it may be easier to relocate electrical service areas than mechanical areas or
structural elements. Allocation of space for electrical areas is often given secondary consider-
ation by plant engineering, architectural, and related specialties. In the competing search for
space, the electrical engineer is responsible for fulfilling the requirements for a proper electri-
cal installation while recognizing the flexibility of electrical systems in terms of layout and
placement.

It is essential that the electrical engineer responsible for designing plant power systems have
an understanding of the manufacturing processes and work flow to the extent that he can form
part of the planning team and assure that the optimum design is provided. In manufacturing
areas, considerations of architectural finishes and permanence are usually secondary to pro-
duction efficiency and flexibility. Special provisions could be required, as part of the manu-
facturing process, for reduction of EMI (see 1.19.3), for continuity of supply, and for
complex control systems.

1.12.1 Coordination of design

Depending on the type and complexity of the project, the engineer will need to cooperate
with a variety of other specialists. These potentially include mechanical, chemical, process,
civil, structural, industrial, production, lighting, fire protection, and environmental engineers;
maintenance planners; architects; representatives of federal, state, and local regulatory agen-
cies; interior and landscape designers; specification writers; construction and installation con-
tractors; lawyers; purchasing agents; applications engineers from major equipment suppliers

IEEE

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CHAPTER 1

and the local electrical utility; and management staff of the organization that will operate the
facility.

The electrical designer must become familiar with local rules and know the authorities having
jurisdiction over the design and construction. It can be inconvenient and embarrassing to have
an electrical project held up at the last moment because proper permits have not been
obtained; for example, a permit for a street closing to allow installation of utilities to the site
or an environmental permit for an on-site generator.

Local contractors are usually familiar with local ordinances and union work rules and can be
of great help in avoiding pitfalls. In performing electrical design, it is essential, at the outset,
to prepare a checklist of all the design stages that have to be considered. Major items include
temporary power, access to the site, and review by others. Certain electrical work may appear
in non-electrical sections of the specifications. For example, furnishing and connecting of
electric motors and motor controllers may be covered in the mechanical section of the speci-
fications. For administrative control purposes, the electrical work may be divided into a num-
ber of contracts, some of which may be under the control of a general contractor and some of
which may be awarded to electrical contractors. Among items with which the designer will be
concerned are preliminary cost estimates, final cost estimates, plans or drawings, technical
specifications (the written presentation of the work), materials, manuals, factory inspections,
laboratory tests, and temporary power. The designer may also be involved in providing infor-
mation on electrical considerations that affect financial justification of the project in terms of
owning and operating costs, amortization, return on investment, and related items.

1.12.2 Flexibility

Flexibility of the electrical system means adaptability to development and expansion as well
as to changes to meet varied requirements during the life of the facility. Sometimes a designer
is faced with providing power in a plant where the loads may be unknown. For example,
some manufacturing buildings are constructed with the occupied space designs incomplete
(shell and core designs). In some cases, the designer will provide only the core utilities avail-
able for connection by others to serve the working areas. In other cases, the designer may lay
out only the basic systems and, as the tenant requirements are developed, fill in the details. A
manufacturing division or tenant may provide working space designs.

Because it is usually difficult and costly to increase the capacity of feeders, it is important that
provisions for sufficient capacity be provided initially. Industrial processes, including manu-
facturing, may require frequent relocations of equipment, addition of production equipment,
process modifications, and even movement of equipment to and from other sites; therefore, a
high degree of system flexibility is an important design consideration.

Extra conductors or raceway space should be included in the design stage when additional
loads are added. In most industrial plants, the wiring methods involve exposed conduits,
cable trays, and other methods where future changes will not affect architectural finishes.
When required, space must be provided for outdoor substations, underground systems includ-
ing spare ducts, and overhead distribution.

OVERVIEW

IEEE
Std 141-1993

Flexibility in an electrical wiring system is enhanced by the use of oversize or spare race-
ways, cables, busways, and equipment. The cost of making such provisions is usually rela-
tively small in the initial installation. Space on spare raceway hangers and openings (sealed
until needed) between walls and floors may be provided at relatively low cost for future work.
Consideration should be given to the provision of electrical distribution areas for future
expansion. Openings through floors should be sealed with fireproof (removable) materials to
prevent the spread of fire and smoke between floors. For computer rooms and similar areas,
flexibility is frequently provided by raised floors made of removable panels, providing access
to a wiring space between the raised floor and the slab below.

Industrial facilities most frequently use exposed wiring systems in manufacturing areas for
greater economy and flexibility. Plug-in busways and trolley-type busways can provide a con-
venient method of serving machinery subject to relocation. Cable trays for both power and
control wiring are widely used in industrial plants. Exposed armored cable is a possible con-
venient method of feeding production equipment.

1.12.3 Specifications

A contract for installation of electrical systems consists of both a written document and draw-
ings. The written document contains both legal (non- technical) and engineering (technical)
sections. The legal section contains the general terms of the agreement between contractor
and owner, such as payment, working conditions, and time requirements, and it may include
clauses on performance bonds, extra work, penalty clauses, and damages for breach of
contract.

The engineering section includes the technical specifications. The specifications give descrip-
tions of the work to be done and the materials to be used. It is common practice in larger
installations to use a standard outline format listing division, section, and subsection titles or
subjects of the Construction Specifications Institute (CSI). 23 Where several specialties are
involved. Division 16 covers the electrical installation and Division 15 covers the mechanical
portion of the work. The building or plant automation system, integrating several building
control systems, is covered in CSI Division 13 — Special Construction. It is important to note
that some electrical work will almost always be included in CSI Divisions 13 and 15. Divi-
sion 16 has a detailed breakdown of various items, such as switchgear, motor starters, and
lighting equipment, specified by CSI.

To assist the engineer in preparing contract specifications, standard technical specifications
(covering construction, application, technical, and installation details) are available from
technical publishers and manufacturers (which may require revision to avoid proprietary
specifications). Large organizations, such as the U.S. Government General Services Adminis-
tration and the Veterans Administration, develop their own standard specifications. The engi-
neer should keep several cautions in mind when using standard specifications. First, they are
designed to cover a wide variety of situations, and consequently they will contain consider-
able material that will not apply to the specific facility under consideration, and they may lack
other material that should be included. Therefore, standard specifications must be appropri-

23 601 Madison Avenue, Industrial Park, Alexandria, VA 22314.

IEEE

Std 141-1993

CHAPTER 1

ately edited and supplemented to embody the engineer’s intentions fully and accurately. Sec-
ond, many standard specifications contain material primarily for non-industrial facilities, and
may not reflect the requirements of the specific industrial processes.

MASTERSPEC, issued by American Institute of Architects (AIA), permits the engineer to
issue a full-length specification in standardized format. SPECTEXT II, which is an abridged
computer program with similar capabilities, is issued by CSI. CEGS and NFGS are the
U.S. Army Corps of Engineers and the U.S. Naval Facilities Engineering Command Guide
Specifications.

Computer-aided specifications (CAS) have been developed that will automatically create
specifications as an output from the CAE-CADD process (see 1.12.4).

1.12.4 Drawings

Designers will usually be given preliminary architectural drawings as a first step. These draw-
ings permit the designers to arrive at the preliminary scope of the work, roughly estimate the
requirements, and determine in a preliminary way the location of equipment and the methods
and types of lighting. In this stage of the design, such items as primary and secondary distri-
bution systems and major items of equipment will be decided. The early requirements for
types of machinery to be installed will be determined. If a typical plant of the type to be built
or modernized exists, it would be well for the engineer to visit such a facility and to study its
plans, cost, construction, and operational history.

Early in the design period, the designer should emphasize the need for room to hang conduits
and cable trays, crawl spaces, structural reinforcements for equipment, and special floor load-
ings; and for clearances around substations, switchgear, transformers, busways, cable trays,
panelboards, switchboards, and other items that may be required. It is much more difficult to
obtain such special requirements once the design has been committed. The need for install-
ing, removing, and relocating machinery must also be considered.

The one-line diagrams should then be prepared in conformity with the utility’s service
requirements. Based on these, the utility will develop a service layout. Checking is an essen-
tial part of the design process. The checker looks for design deficiencies in the set of plans.
The designer can help the checker by having on hand reference and catalog information
detailing the equipment he has selected. The degree of checking is a matter of design policy.

Computer-aided engineering (CAE) and computer-aided design and drafting (CADD) sys-
tems are tools by which the engineer/designer can perform automatic checking of interfer-
ences and clearances with other trades. The development of these computer programs has
progressed to the level of automatically performing load-flow analysis, fault analysis, and
motor-starting analysis from direct entry of the electrical technical data of the components
and equipment.

24 1735 New York Avenue, NW, Washington, DC 20006.

OVERVIEW

IEEE
Std 141-1993

1.12.5 Manufacturer’s or shop drawings

After the design has been completed and contracts are awarded, contractors, manufacturers
and other suppliers will submit drawings for review or information. It is important to review
and comment upon these drawings and return them as quickly as possible; otherwise, the
supplier and/or contractor may claim that the work was delayed by the engineer’s review
process. Unless the drawings contain serious errors and/or omissions, it is usually a good
practice not to reject them but to stamp the drawings with terminology such as “revise as
noted’’ and mark them to show errors, required changes, and corrections. The supplier can
then make appropriate changes and proceed with the work without waiting to resubmit the
drawings for approval.

If the shop drawings contain major errors or discrepancies, however, they should be rejected
with a requirement that they be resubmitted to reflect appropriate changes that are required on
the basis of notes and comments of the engineer.

Unless otherwise directed, communication with contractors and suppliers is always through
the construction (often inspection) authority. In returning corrected shop drawings, remember
that the contract for supplying the equipment is usually with the general contractor and that
the official chain of communication is through him or her. Sometimes direct communication
with a subcontractor or a manufacturer may be permitted; however, the content of such com-
munication should always be confirmed in writing with the general contractor. Recent law-
suits have resulted in placing the responsibility for shop drawing correctness (in those cases
and possibly future cases) upon the design engineer, leaving no doubt that checking is an
important job.

1.13 Estimating

A preliminary estimate is usually requested. Sometimes the nature of a preliminary estimate
makes it nothing more than a good guess. Enough information is usually available, however,
to perform the estimate on a square foot, per process machine, per production area, by the
horsepower or number of motors, or on a similar basis for a comparable facility.

A second estimate is often provided after the project has been clearly defined but before any
drawings have been prepared. The electrical designer can determine from sketches and archi-
tectural layouts the type of lighting fixtures as well as many items of heavy equipment that
are to be used. Lighting fixtures, as well as most items of heavy equipment, can be priced
directly from the catalogs, using appropriate discounts.

The most accurate estimate is made when drawings have been completed and bids are about
to be received or the contract negotiated. The estimating procedure of the designer in this
case is similar to that of the contractor’s estimator. It involves first the takeoffs, that is, count-
ing the number of receptacles, lighting fixtures, lengths of wire and conduit, determining the
number and types of equipment, and then applying unit costs for labor, materials, overhead,
and profit.

IEEE

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CHAPTER 1

The use of standard estimating sheets is a big help. Various forms are available from the
National Electrical Contractors’ Association (NECA). For preliminary estimates, there are
a number of general estimating books that give unit cost figures (often per square foot) and
other general costs, such as the following three titles: Building Construction Cost Data;
Mechanical Cost Data; and Electrical Cost Data. 26 Several computer programs permit
streamlining and standardizing engineering estimating.

Chapter 16 illustrates the detailed procedures for making estimates for industrial facilities.

Extra work (“extras”) refers to work performed by the contractor that has to be added to the
contract because of unforeseen conditions or changes in the scope of work. The contractor is
not usually faced with competition in making these changes; therefore, extra work is
expected to be more costly than the same work would be if included in the original contract.
Extra cost on any project can be minimized by giving greater attention to design details in the
original planning stage. On rehabilitation or modification work, extras are more difficult to
avoid; however, with careful field investigation, extras can be held to a minimum.

1.14 Contracts

Contracts for construction may be awarded on either a lump-sum or a unit-price basis, or on a
cost-plus (time-and-material) basis. A lump sum involves pricing the entire job as one or sev-
eral major units of work.

The unit-price basis simply specifies so much per unit of work, for example, so many dollars
per foot of 3-inch conduit. The lump-sum contract is usually preferable when the design can
be worked out in sufficient detail. The unit-price contract is desirable when it is not possible
to determine exactly the quantities of work to be performed and when a contractor, in order to
provide a lump-sum contract, might have to overestimate the job to cover items that could not
accurately be determined from the drawings.

If the unit-price basis is used, the estimated quantities should be as accurate as possible, oth-
erwise it may be advantageous for the contractor to quote unit prices of certain items as high
as possible and reduce other items to a minimum figure. It could be to the contractor’s advan-
tage to list those items highest on which payment would be received first or those items that
would be most likely to increase in quantity.

The time-and-material basis is valuable for emergency or extra work where it would be
impractical to use either of the above two methods. It has the disadvantage of requiring a
close audit of manpower and material expenditures of the contractor. Where only a part of the
work is not clearly defined, a combination of the three pricing methods might be in order.

25 73 15 Wisconsin Avenue, Bethesda, MD 20814.

26 Published by R. Snow Means Co., 100 Construction Plaza Avenue, Kingston, MA.

OVERVIEW

IEEE
Std 141-1993

1.15 Access and loading

It is imperative that the equipment fit into the area specified and that the floor-load rating be
adequate for the weight of the equipment. Sizes of door openings, corridors, and elevators for
moving of equipment (initially and for maintenance and replacement purposes) must be
checked. However, it is easy to forget that equipment has to be moved across floors, and that
the floor-load ratings of the access areas for moving the equipment must be adequate for this.
If floor strengths are not adequate, provision must be made to reinforce the floor or, if prac-
tical, to specify that the load be distributed so that loading will not exceed structural
limitations.

It is important to review weights and loadings with the structural engineers. Sometimes it is
necessary to provide removable panels, temporarily remove windows, and even to make
minor structural changes in order to move large and heavy pieces of equipment or machinery.
Provisions also must be made for removal of equipment for replacement purposes. Clear-
ances must be in accordance with code provisions regarding working space. Clearance must
also be provided for installation, maintenance, and such items as cable pulling, transformer
replacement, maintenance/testing, and switchgear-drawout space. It is often essential to
phase items of work in order to avoid conflict with other electrical work or work of other
trades.

1.16 Contractor performance

Contractors may be selected on the basis of bid or quoted price or by negotiation. Govern-
mental or corporate policies may mandate selection of the lowest qualified bidder. Where the
relative amount of electrical work is large, the contract may be awarded to an electrical con-
tractor. In other instances, the work may be awarded to an electrical subcontractor by the
overall general contractor.

The performance of the work will usually be monitored and inspected by representatives of
the owner and the engineer-of-record. The work may be subject to the inspection of govern-
mental and other assigned approval agencies, such as insurance underwriters. The designer
may communicate with the contractor only to the extent permitted by the agency exercising
control over the contract.

It is essential that designers, in attempting to expedite the contract, not place themselves in
the position of requesting without proper authorization, or “reading into” the contract, what is
not clearly required by the specifications or drawings.

The contract may require the contractor to deliver, at the end of the work, revised contract
drawings, known as “as-built” drawings. These show all changes in the work that may have
been authorized, or details that were not shown on the original drawings.

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1.17 Environmental considerations

In all branches of engineering, an increasing emphasis is being placed on social and environ-
mental concerns. Today’s engineer must consider air, water, noise, lighting, and other items
that have an environmental impact. The limited availability of energy sources and the steadily
increasing cost of electric energy require that energy conservation be addressed.

This issue is becoming more than just a matter of conscience or professional ethics. Laws,
codes, rules, and standards issued by legislative bodies, governmental agencies, public ser-
vice commissions, insurance, and professional organizations (including groups whose pri-
mary concern is the protection of the environment and conservation of natural resources)
increasingly require an assessment of how the project may affect the environment. Energy
conservation is covered in Chapter 14. Environmental studies, which include the effect of
noise, vibration, exhaust gasses, lighting, and effluence, must be considered in relationship to
the working environment, the general environment, and the public.

Landscape architects can provide pleasing designs of trees and shrubbery to completely con-
ceal outdoor substations and overhead lines may, of course, be replaced by underground sys-
tems. Substations situated in residential areas must be carefully located so as not to create a
local nuisance. Precast sound barriers can reduce transformer and other electrical equipment
noise. Floodlighting and parking-lot lighting must not spill onto adjacent areas where it may
provide undesirable glare or lighting levels (see IES Committee Report CP-46-85 [B9]). The
engineer should keep up-to-date on developments in the areas of environmental protection
and energy conservation. Federal Environmental Protection Agency guidelines and judicial
rulings on local environmental litigation are generally covered in the Federal Register and in
the periodicals previously listed.

1.1 8 Technical files

Drawings and other technical files are often kept in file cabinets as originals or copies. A sys-
tem of filing and reference is essential when many such items are involved. A computerized
data base may a valuable method of referencing and locating the proper document. When
drawings are produced by computer-graphic systems, such as CADD, magnetic tape may be
used for storage. Plotters can be used with computer systems to produce hard copy. Original
drawings (often prepared on tracing material) can be stored photographically on film; the
drawings can be made available on viewers or enlarger-printers. Microfiche involves placing
the microfilm on computer-type cards for handling manually or in data-processing type
systems.

1.19 Electronic systems

Electronic systems are a major item in industrial facilities for control purposes, motor con-
trol, lighting ballasts, communication systems, data processing, computer applications,
industrial process control, data management, and plant (building) management systems. This
subclause is concerned primarily with the effects of the power supply, control and power

OVERVIEW

IEEE
Std 141-1993

wiring, and interference on these systems; and with some indication of the extent of the use
of electronic equipment in industrial facilities.

Industrial processes often require a degree of speed and torque control of motors, which is
obtainable through the use of electronic controllers and computer-based control systems (see
Chapter 10). Electronic power supplies/controllers are used for supplying power to heat-
process systems and to electrochemical processes. The electronic controller has the advan-
tage of being able to tie together the power equipment, the control computers, the sensing
equipment, data acquisition and display systems, robotics, and telemetering equipment into
an effective package. Subclause 1.3.1 lists the committees, by industry and application, that
are involved with and publish extensive technical material in this area.

1.19.1 Power supply disturbances

The power supply to equipment may contain transients and other short-term under- or over-
voltages that result primarily from switching operations, faults, motor starting, lightning dis-
turbances, switching of capacitors, electric welding, and operation of heavy manufacturing
equipment. The system may also contain a harmonic content as described in 1.19.2 below.
These electrical disturbances may be introduced anywhere on an electric system or in the util-
ity supply, even by other utility customers connected to the same circuits. A term frequently
applied to describe the absence or presence of these power deficiencies is power quality. The
IEEE Emerald Book (see 1.3.2) examines in detail the effects of the power supply on equip-
ment performance. It covers methods of diagnosing and correcting performance problems
related to the power supply.

1.19.2 Harmonics

Chapter 9 of this book, Chapter 10 of the Brown Book, the Emerald Book, and IEEE Std
519-1992 [B5] all contain discussion of harmonics. Harmonics are integral multiples of the
fundamental (line) frequency involving nonlinear loads or control devices, including electro-
magnetic devices (transformers, lighting ballasts) and solid-state devices (rectifiers, thyris-
tors, phase-controlled switching devices). In the latter grouping are power rectifiers,
adjustable-speed electronic controllers, switching-mode power supplies (used in smaller
computers), and UPS systems.

Harmonics can cause or increase EMI in sensitive electronic systems, abnormal heating or
cables and motors, transformers, and other electromagnetic equipment, excessive capacitor
currents, and excessive voltages because of system resonances at harmonic frequencies.

Recently, it has been determined that the harmonic content of multiwire systems having a
high proportion of switching-mode power supplies is very high. The neutral conductors of
these systems must be sized at greater than full rating, and transformers must be derated or
designed for high-harmonic content. A full discussion of harmonics is beyond the scope of
this subclause; reference should be made to the previously mentioned publications.

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CHAPTER 1

1.19.3 Electromagnetic interference (EMI)

EMI is the impairment of a wanted electromagnetic signal by an electromagnetic disturbance.
EMI can enter equipment either by conduction through power, grounding, control, data, or
shielding conductors, or by induction from local electromagnetic or electrostatic fields. The
most common causes of EMI problems in sensitive equipment, such as computers, communi-
cations equipment, and electronic controllers, are poor inherent design of the equipment or
power supply, poor grounding, and unsound design of the equipment interfaces.

It can be reduced by the use of effective grounding (both electronic and equipment grounds),
shielding, twisted conductors (pairs) and coaxial cables, and effective use of conduit (espe-
cially steel conduit) for control and power (where practical) circuits [B3], [B4J. EMI and
other power problems can cause control and equipment malfunctions, slowing of computer
operations, lack of reliability, and failure of critical systems. These failures can affect product
quality and, in some cases, worker safety.

The use of filters, voltage regulators, surge capacitors, surge arresters, isolation transformers
(particularly with electrostatic shielding between coils), power conditioners, UPS systems, or
motor-generator sets for isolation are all methods of reducing EMI. Fiber-optic cables and
electro-optical isolation at interfaces are extremely effective methods of providing isolation
between systems.

1.20 Programmable logic controller (PLC)

The PLC is a microprocessor designed for control and telemetering systems. It is pro-
grammed to accept “ladder-type” logic, which enables the operator to use relay-type logic,
thereby avoiding the need to use the conventional software languages. The equipment can be
housed in cases suitable for mounting in exposed locations and on production floors.

1.21 Bibliography

[B 1 ] ANSI C84. 1-1989, American National Standard Electric Power Systems and Equip-
ment-Voltage Ratings (60 Hz).

[B2J ANSI/NFPA 70-1993, National Electrical Code.

[B3] Griffith, D. C., Uninterruptible Power Supplies, Marcel Decker, Inc., 1989.

[B4] IEEE Std 518-1982 (Reaff 1990), IEEE Guide for the Installation of Electrical Equip-
ment to Minimize Noise Inputs to Controllers from External Sources (ANSI).

[B5J IEEE Std 519-1992, IEEE Recommended Practices and Requirements for Harmonic
Control in Electric Power Systems (ANSI).

OVERVIEW

IEEE
Std 141-1993

[B6] IEEE Std 100-1992, The New IEEE Standard Dictionary for Electrical and Electronics
Terms (ANSI).

[B7] IEEE Std 693-1984 (Reaff 1991), IEEE Recommended Practices for Seismic Design of
Substations (ANSI).

[B8] IEEE Std 979-1984 (Reaff 1988), IEEE Guide for Substation Fire Protection (ANSI).
[B9] IES Committee Report CP-46-85, “Astronomical Light Pollution and Light Trespass.”

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Chapter 2
System planning

2.1 Introduction

The continuity of production in an industrial plant is only as reliable as its electric power dis-
tribution system. This chapter outlines procedures and various considerations for system
planning and presents a guide to the use of the succeeding chapters.

No standard electric distribution system is adaptable to all industrial plants, because two
plants rarely have the same requirements. The specific requirements must be analyzed quali-
tatively for each plant and the system designed to meet its electrical requirements. Equal and
adequate consideration must be given to both the present and future operating and load
conditions.

2.2 Definitions

See 2.4. 1.3 for definitions related to demand.

2.3 Basic design considerations

The approach to system planning should include several basic considerations that will affect
the overall design and operation.

2.3.1 Safety

Safety of life and preservation of property are two of the most important factors to be consid-
ered in the design of the electric system. Codes must be followed and recommended practices
or standards should be followed in the selection and application of material and equipment.

Equally important is providing equipment that is properly and adequately sized and rated to
handle available fault levels in the system in accordance with established fault duty calcula-
tion procedures. Adequate safety features should be incorporated into all parts of the system.

Listed below are the electric system operating and design limits that should be considered in
order to provide safe working conditions for personnel:

a) Interrupting devices must be able to function safely and properly under the most
severe duty to which they may be exposed.

b) Protection must be provided against accidental contact with energized conductors,
such as enclosing the conductors, installing protective barriers, or installing the con-
ductors at sufficient height to avoid accidental contact.

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CHAPTER 2

c) Isolating switches must not be operated while they are carrying current, unless they
are designed to interrupt such current. They should be equipped with safety inter-
locks and warning signs if load or transformer magnetizing current-load-interrupting
and fault-closing capability are not provided.

d) In many instances it is desirable to isolate a power circuit breaker using disconnect
switches. In such cases, the circuit breaker must be opened before the disconnect
switches. Safety interlocks to ensure this sequence should be used, together with
detailed and specific personnel operating instructions.

e) The system should be designed so that maintenance work on circuits and equipment
can be accomplished with the particular circuits and equipment de-energized and
grounded. System design should provide for locking out circuits or equipment for
maintenance, including grounding instructions. A written procedure should be estab-
lished to provide instructions on tagging or locking out circuits during maintenance,
and re-energizing after completion of the maintenance work following disconnection
of the grounding equipment.

f) Electric equipment rooms, especially those containing apparatus over 600 V, such as
transformers, motor controls, or motors, should be equipped and located to eliminate
or minimize the need for access by nonelectrical maintenance or operating personnel.
Conveniently located exits should be provided to allow quick exit during an
emergency.

g) Electric apparatus located outside special rooms should be provided with protection
against mechanical damage due to equipment location, personnel access, and vehicu-
lar traffic. The area should be accessible to maintenance and operating personnel for
emergency operation of protective devices.

h) Equipment location should be carefully considered. A nonhazardous area should be
set aside for electrical equipment, or it may be necessary to locate explosion-proof
equipment in the hazardous area. The advantages and disadvantages of not only ini-
tial cost but the maintenance cost and the ability to maintain the integrity of the
equipment should all be carefully considered.

i) Warning signs should be installed on electric equipment accessible to unqualified
personnel, on fences surrounding electric equipment, on doors giving access to elec-
trical rooms, and on conduits or cables above 600 V in areas that include other equip-
ment or pipelines. An electrical single-line diagram should be installed in each
electrical switching room.

j) An adequate grounding system must be installed.

k) Emergency lights should be provided where necessary to protect personnel against
sudden lighting failure. In facilities, the Life Safety Codes requires that escape routes
and exits have emergency lighting. In addition, process control locations and electric
switching centers should be equipped with standby lighting.

l) Operating and maintenance personnel should be provided with complete operating
and maintenance instructions, including wiring diagrams, equipment ratings, and
protective device settings. Spare fuses of the correct ratings should be stocked.

2.3.2 Reliability of plant primary utility supply service

The continuity of service required is dependent on the type of manufacturing or process oper-
ation of the plant and the cost of that operation, especially if it is interrupted. Some plants can

SYSTEM PLANNING

IEEE
Std 141-1993

tolerate interruptions while others require the highest degree of service continuity. The sys-
tem should always be designed to isolate faults with a minimum disturbance to the system
and should have features to give the maximum dependability consistent with the plant
requirements and justifiable cost.

The majority of utilities today supply energy to medium and large industrial customers
directly at 34.5, 69, 115, 138, 161 and 230 kV using dedicated substations. Small industrial
complexes may receive power at voltages as low as 4 kV.

Some industrial plants accept supplies directly from utility area distribution substations at
4.16, 12.5, 13.8 kV, etc. In most instances, the utility substations also serve other customers
so that there are usually several distribution lines connected to the same bus as the plant sup-
ply line(s), although in some cases dedicated services, including bus(es) and lines, are pro-
vided. For the most part, plant personnel feel secure with this type of supply, especially if the
supply substation is nearby and if multiple supply lines are provided to meet firm power or
first contingency requirements. However, these provisions can create a false sense of security,
especially when the facts regarding the reliability of distribution lines, the impact of nearby
customer faults and system operations on such services, and the impact this has on plant
operations are overlooked. For example, when a fault occurs on the supply system near the
plant, there is an accompanying voltage sag on all of the plant primary distribution and utili-
zation voltage buses. This lowered voltage persists while the utility relays operate and until
the utility breaker trips, at which point the voltage will be reduced to zero on the faulted line
and will be restored to near normal on the unfaulted portions of the system. Experience has
shown that these short-time voltage sags are often severe enough and persist long enough to
cause the solenoid coils of mechanical contactors and relays to open automatically. When this
occurs in a plant there will be parts damage, tool breakage, lost production, etc., all of which
cause major disruptions in plant operations even though the supply may be lost only tempo-
rarily. Furthermore, new customers added to the area distribution supply substation can also
reduce the quality and reliability of the service.

Lower voltage distribution services often tend to be older systems that are susceptible to a
more frequent rate of system interruption and failure than higher voltage transmission sys-
tems. Underground, lower voltage cable systems are especially susceptible, although some
underground cable systems have proven to have high reliability. This reliability tends to be
very site- and utility- specific. Installation, maintenance, age, and workmanship quality on
cable terminations and splices can all significantly affect the reliability of such systems. Sta-
tistically, 138 kV lines may have interruption rates of four or five interruptions per hundred
miles per year. On the other hand, distribution lines in the 8-23 kV voltage range may have
interruption rates of 100 or more interruptions per hundred miles per year. Thus, the probabil-
ity of damaging voltage sags is at least 20 times as great on distribution lines as on transmis-
sion voltage lines. This difference in probabilities is magnified even more when it is realized
that the exposure to voltage sag incidents includes many nearby interconnected lines not nec-
essarily dedicated to the plant supply.

Depending upon circumstances, the capacity available for future expansion from area substa-
tions may often be limited, even with or without a single contingency situation occurring.
Available capacity may be limited by a transformer, switch, circuit breaker, bus, protective

IEEE

Std 141-1993

CHAPTER 2

device(s) and supplying cable capacity and, therefore, requires careful evaluation for both
normal and abnormal operating conditions. In addition, if firm or first contingency capacity is
desired, then the availability of duplicate capacity in the transformer(s), protective device(s),
and cables must all be taken into account. Expansion of available capacity in such circum-
stances to meet first contingency needs may present difficulties due to station configuration
and the impact on other customers, especially if available user fault levels are changed as a
result of the expansion. This aspect requires very careful consideration so capacity con-
strained conditions do not develop that will later present significant technical and economical
difficulties in meeting increased plant loads.

2.3.3 Plant distribution system reliability analysis

One of the questions often raised during the design of the plant power distribution system is
how to make a quantitative comparison of the failure rate and the forced downtime in hours
per year for different circuit arrangements, including radial, primary-selective, secondary-
selective, simple spot network, and secondary-network circuits. This quantitative comparison
could be used in trade-off decisions involving the initial cost versus the failure rate and forced
downtime per year. The estimated cost of power interruptions at the various distribution
points should be considered in deciding which type circuit arrangement to use. The decisions
should be based upon total owning cost over the useful life of the equipment rather than the
first cost.

In general, electric power systems are designed on a first contingency basis. The incremental
cost to provide such services is typically a relatively small cost as compared to the total facil-
ity or plant cost. The risk and cost of a long-term interruption due to system failure far out-
weighs the added incremental cost required to provide first contingency capacity at the time
of installation.

2.3.3. 1 Reliability data for electrical equipment

In order to calculate the failure rate and the forced downtime per year, it is necessary to have
reliability data on the electric utility supply and each piece of electrical equipment used in the
power distribution system. One of the best sources for this type of data are the extensive IEEE
surveys on the reliability of electrical equipment in industrial plants and commercial build-
ings. (See IEEE Std 493-1 990. *) While this data may be quite useful, it represents a limited
data base; therefore, it may not be representative of an individual company’s experience. In-
house data, if available, may be more appropriate in this analysis.

2.3.3.2 Reliability analysis and total owning cost

Statistical analysis methods involving probability of failure may be used to make calculations
of the failure rate and the forced downtime for the power distribution system. The methods
and formulas used in these calculations are given in IEEE Std 493-1980. This includes the
minimum revenue requirements method for calculating the total owning cost over the useful

'information on references can be found in 2.6.

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IEEE
Std 141-1993

life of the equipment. Data and calculations for determining the cost of power interruptions
are also given in IEEE Std 493-1990.

2.3.4 Simplicity of operation

Simplicity of operation is very important in the safe and reliable operation and maintenance
of the industrial power system. The operation should be as simple as possible to meet system
requirements.

2.3.5 Voltage regulation

Poor voltage regulation is detrimental to the life and operation of electrical equipment. Volt-
age at the utilization equipment must be maintained within equipment tolerance limits under
all load conditions, or equipment must be selected to operate safely and efficiently within the
voltage limits. Use load-flow studies and motor-starting calculations to verify voltage
regulation.

2.3.6 Maintenance

The distribution system should include provisions for predictive and preventive maintenance
requirements in the initial design. Accessibility and availability for inspection and repair with
safety are important considerations in selecting equipment. Space should be provided for
inspection, adjustment, and repair in clean, well-lighted, and temperature-controlled areas.

2.3.7 Flexibility

Flexibility in an electric system means expandability as well as adaptability to changing
requirements during the life of the plant. Consideration of the plant voltages, equipment rat-
ings, space for additional equipment, and capacity for increased load must be given serious
study.

2.3.8 First cost

While first costs are important, safety, reliability, voltage regulation, maintenance, and the
potential for expansion should also be considered in selecting the best from alternate plans.

2.4 Planning guide for the supply and distribution system

The following procedure will guide the engineer in the design of an electric distribution sys-
tem for an industrial plant. The system designer should also have or acquire knowledge of the
plant’s processes in order to select the proper system and its components.

2.4.1 Load definition and forecasting

Load definition entails load surveys, demand and diversity analysis, and load characteristic
definition. In addition, load forecasting for future requirements must be considered.

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CHAPTER 2

2.4.1. 1 Load survey

Obtain a general plant or facility layout, mark it with the known major loads at various loca-
tions, and determine the approximate total plant load in kilowatts or kilovoltamperes. Initially
the amount of accurate load data may be limited; therefore, some loads, such as lighting and
air conditioning, may be estimated from generalized data. The majority of industrial plant
loads are a function of the process equipment, and such information will have to be obtained
from process and equipment designers. Since their design is often concurrent with power sys-
tem design, initial information will be subject to change. It is important, therefore, that there
be continuing coordination with the other design disciplines. For example, a change from
electric powered to absorption refrigeration or a change from electrostatic to high-energy
scrubber air-pollution control can change the power requirements for these devices by several
orders of magnitude. The power system load estimates will require continual refinement until
job completion.

2.4.1. 2 Load requirements and characteristics

The following items define the various requirements and characteristics of the loads and must
be determined and defined in the planning process;

a) Load development/build-up schedule

1) Peak load requirements in kilovoltamperes

2) Temporary/construction power requirements

3) Timing

b) Load variations in kilovoltamperes expected during low load (non-productive
periods), average load, and peak load conditions.

c) Nature of load in terms of its occurrence

1 ) Continuous

2) Intermittent

3) Cyclical

4) Special or unusual loads

5) Combination of above

d) Expected power factor during low load (nonproductive periods), average load, and
peak load periods.

e) Expected daily and annual load factor:

avg. kW
peak kW

_ avg. kW
peak kW

1 ) Horsepower and other nameplate data

2) Type (synchronous/induction)

3) System nominal voltage

4) Starting requirements

5) Application

kWh for 24 h/24 h
peak kW during the 24 h

kWh for 8670 h/8670 h
peak kW during the 8670 h

Large motor-starting requirements

Daily

Annual

SYSTEM PLANNING

IEEE
Std 141-1993

g) Special or unusual loads such as

1) Resistance welding

2) Arc welding

3) Induction melting

4) Induction heating

5) Heat treating

6) SCR controlled ovens

7) Variable speed drives (large press drives)

8) Large power conversion devices

h) Harmonic-generating loads

1) Converter/inverter drives

2) Arc discharge lighting

3) Arc furnaces

4) Other

i) Special power quality requirements for sensitive or critical loads

1) Data processing operations

2) Special machines

3) Continuous process loads

4) Others

2.4.1. 3 Demand

The sum of the electrical ratings of each piece of equipment will give a total connected, non-
coincident load. Because some equipment operates at less than full load and some intermit-
tently, the resultant demand upon the power source is always less than the total connected
load, so appropriate load diversity considerations should be considered in the analysis. In
general, equipment diversities range from slightly less than 100% for a continuous process to
as low as 2% to 5% for certain types of press and welding operations. The diversity expecta-
tion associated with each type of equipment should be used to develop a specific, total, actual
expected load. An appropriate diversity should then also be applied to each large grouping of
equipment and to the entire load to reflect randomness and physical reality, based on
experience.

Standard definitions for these load combinations and their ratios have been devised.

2.4.1.3.1 demand: The electric load at the receiving terminals averaged over a specified
interval of time.

Note that demand is expressed in kilowatts, kilovoltamperes, amperes, or other suitable units.
The interval of time is generally 15 min, 30 min, or 1 h, based on the particular utility’s
demand metering interval.

2.4.1.3.2 peak load: The maximum load consumed or produced by a unit or group of units
in a stated period of time. It may be the maximum instantaneous load or the maximum aver-
age load over a designated period of time.

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2.4.1.3.3 maximum demand: The greatest of all demands that have occurred during a spec-
ified period of time such as one-quarter, one-half, or one hour.

Note that for utility billing purposes the period of time is generally one month.

2.4.1.3.4 demand factor: The ratio of the maximum coincident demand of a system, or part
of a system, to the total connected load of the system, or part of the system, under consider-
ation. The resultant is always 1 or less and can range from 0.8 to 1 to as low as 0.15 to 0.25
for some plants with very low diversity.

2.4.1.3.5 diversity factor: The ratio of the sum of the individual non-coincident maximum
demands of various subdivisions of the system to the maximum demand of the complete sys-
tem. The diversity factor is always 1 or greater. The (unofficial) term diversity, as distin-
guished from diversity factor refers to the percent of time available that a machine, piece of
equipment, or facility has its maximum or nominal load or demand (i.e., a 70% diversity
means that the device in question operates at its nominal or maximum load level 70% of the
time that it is connected and turned on).

2.4.1.3.6 load factor: The ratio of the average load over a designated period of time to the
peak load occurring in that period.

Note that although not part of the official definition, the term load factor is used by some util-
ities and others to describe the equivalent number of hours per period the peak or average
demand must prevail in order to produce the total energy consumption for the period.

2.4.1.3.7 coincident demand: Any demand that occurs simultaneously with any other
demand, also the sum of any set of coincident demands.

Information on these factors for the various loads and groups of loads is useful in designing
the system. For example, the sum of the connected loads on a feeder, multiplied by the
demand factor of these loads, will give the maximum demand that the feeder must carry. The
sum of the individual maximum demands on the circuits associated with a load center or pan-
elboard, divided by the diversity factor of those circuits, will give the maximum demand at
the load center and on the circuit supplying it. The sum of the individual maximum demands
on the circuits from a transformer, divided by the diversity factor of those circuits, will give
the maximum demand on the distribution transformer. The sum of the maximum demand on
all distribution transformers, divided by the diversity factor of the transformer loads, will give
the maximum demand on their primary feeder. By the use of the proper factors, as outlined,
the maximum demands on the various parts of the system from the load circuits to the power
source can be estimated. Allowances should also be made for future load expansion in these
calculations.

2.4.1. 4 Forecasting and planning

Essentially, the load forecasting and planning process involves at least six separate consider-
ations. These are as follows:

a) Impact of nominal load growth over time. Typically, some slight growth in kilowatt
demand will be experienced over time. This may be upwards of V 2 to 1% per year;

SYSTEM PLANNING

IEEE
Std 141-1993

b) Impact of equipment changes due to new equipment installations or modifications
that are not part of the product plan, including environmental equipment, new tech-
nology applications, or new requirements, such as facility air conditioning or air
tempering;

c) New and modified production plans to meet requirements of the future product plan;

d) Additional site development due to new on-site building(s) and added floor space.
Typically, a site may be initially developed to a 15-20% building to land ratio, with
an allowance for future development of upwards of 30%. Some sites may be con-
strained for additional development;

e) Impact of gas/oil conversion to electric use for some types of product heating
where electric heating may actually be more economical due to inherent process
efficiencies;

f) Other types of changes that cannot easily be categorized, such as higher density plant
loading, etc.

Every plant should have a current business forecast, for five or six years of production and
project requirements, that may be implemented. These, along with longer term projections,
should be weighed in terms of their impact upon electric demand. In similar fashion, the pros-
pect of future expanded utilization of the site must be recognized in terms of electric demand.
An array of probable plans for capacity can be developed to keep pace with the demands. If
the full range of future possibilities is explored both as to size and timing, long-range plans
can be developed that can potentially meet demands. While typically forecasted requirements
for additional load occur later and are smaller than planned, the process is essential so that
constraints, if present, are fully recognized and plans can be developed to resolve them.

Since forecasting offers a degree of certainty, it would be uneconomical to construct or pro-
vide capacity that is never used. However, there are opportunities in planning and designing
electrical systems for selecting apparatus and arranging these in schemes that minimize the
probabilities of early obsolescence due to improper ratings and the need for reconstructing
major portions of the system.

2.4.2 Plant distribution systems

Investigate the various types of plant distribution systems and select the system or systems
best suited to the requirements of the plant. A variety of basic circuit arrangements is avail-
able for industrial plant power distribution. Selection of the best system or combination of
systems will depend upon the needs of the manufacturing process. In general, system costs
increase with system reliability if component quality is equal. Maximum reliability per unit
investment can be achieved by using properly applied and well-designed components.

The first step is the analysis of the manufacturing process to determine its reliability need and
potential losses and costs in the event of power interruption. Some plant processes are mini-
mally affected by interruption. Here a simple radial system may be satisfactory. Other plant
processes may sustain long-term damage or experience excessive cost by even a brief inter-
ruption, therefore, a more complex system with an alternate power source for critical loads
may be justified.

IEEE

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CHAPTER 2

Circuit redundancy may be needed in continuous-process industries to allow equipment
maintenance. Although the reliability of electric power distribution equipment is high,
optimum reliability and safety of operation still requires routine maintenance. A system that
cannot be maintained because of the need to serve a continuous process is improperly
designed.

Far more can be accomplished by the proper selection of the circuit arrangement than by
economizing on equipment details. Cost reductions should never be made at the sacrifice of
safety and performance by using inferior apparatus. Reductions should be obtained by using
a less expensive distribution system with some sacrifice in reserve capacity and reliability.

2.4.2. 1 Simple radial system

(See figure 2-1.) Distribution is at the utilization voltage. A single primary service and distri-
bution transformer supply all the feeders. There is no duplication of equipment. System
investment is the lowest of all circuit arrangements.

Figure 2-1 —Simple radial system

Operation and expansion are simple. When quality components and appropriate ratings are
used reliability is high. Loss of a cable, primary supply, or transformer will cut off service.
Equipment must be shut down to perform routine maintenance and servicing.

This system is satisfactory for small industrial installations where process allows sufficient
down time for adequate maintenance and the plant can be supplied by a single transformer.

SYSTEM PLANNING

IEEE
Std 141-1993

2.4. 2. 2 Expanded radial system

(See figure 2-2.) The advantages of the simple radial system may be applied to larger loads by
using an expanded radial primary distribution system to supply a number of unit substations
located near the load, which in turn supply the load through radial secondary systems.

The advantages and disadvantages are the same as those described for the simple radial
system.

— <40*>-

TTT T

~ X X X X

1 1 1 1

4) nP vP *

T T T T

TTTT

5 5 5 5

TTTT

NOTE: If non-draw-out
primary fused switches
are used, the fuse should
be on the load side of
the switch.

NOTE: Fused switches
may be used instead of
circuit breakers.

Figure 2-2— Expanded radial system

2.4. 2. 3 Primary selective system

(See figure 2-3.) Protection against loss of a primary supply can be gained through use of a
primary selective system. Each unit substation is connected to two separate primary feeders
through switching equipment to provide a normal and an alternate source. Upon failure of the
normal source, the distribution transformer is switched to the alternate source. Switching can
be either manual or automatic, but there will be an interruption until load is transferred to the
alternate source.

If the two sources can be paralleled during switching, some maintenance of primary cable
and switching equipment, in certain configurations, may be performed with little or no inter-
ruption of service. Cost is somewhat higher than a radial system because of duplication of
primary cable and switchgear.

2.4. 2. 4 Primary loop system

(See figure 2-4.) A primary loop system offers improved reliability and service continuity in
comparison to a radial system. In typical loop systems, power is supplied continuously from
two sources at the ends of the loop. Such a system, if properly designed and operated, can

IEEE

Std 141-1993

CHAPTER 2

T T

t t

£ £

^ ^ 'a' ^ ^ ^ 'A' -A 4

1v t. t. t. t tv t

£ £ £ £ £ £ £ £

1 i I I Till

NOTE: If non-draw-out fused switches are
used, the fuse should be on the load side of the
switch.

NOTE: An alternate arrangement uses a primary
selector switch with a single fused interrupter
switch (which may not have certified current-
switching ability).

Figure 2-3— Primary selective system

quickly recover from a single cable fault with no continuous loss of power to utilization
equipment. It is unlikely that a fault will occur within the area of the closely coupled isolation
devices and the bus to the fuse protecting the transformer.

A second important feature of loop systems is that a section of cable may be isolated from the
loop for repair or maintenance while other parts of the system are still functioning. However,
it is important to analyze the isolation provided with this arrangement.

Since electrical power can flow in both directions in a loop system, it is essential that detailed
operating instructions be prepared and followed. These instructions must take into account
the fact that the industrial facility may not always be staffed with trained electrical personnel
on a 24-hour basis. Additionally, if the two supply points for the loop originate from different
buses, the design must consider available short-circuit capacity from both buses, the ability of
both buses to supply the total load, and the possibility of a flow of current from one bus to the
other bus over the loop.

2.4. 2. 4.1 Closed-loop operation

To realize optimum service reliability of a primary loop system, the system should be oper-
ated with all series switches in figure 2-4 closed (closed-loop mode). When designing a sys-
tem that is expected to be operated in the closed-loop mode, circuit breakers typically are
selected in lieu of fused or nonfused isolation switches.

When the loop switches consist of circuit breakers with interconnected directional overcur-
rent or pilot wire relays, a cable fault within the loop may be automatically isolated without

SYSTEM PLANNING

IEEE
Std 141-1993

loss of transformer capacity. No loss of power will occur, although the system will experience
a voltage dip until the circuit breakers clear the fault. Whenever a section of the loop is
faulted, either in the cable of the loop or in the taps from the loop, both circuit breakers feed-
ing that section must trip. If the taps are taken from nonadjacent sections, then the two circuit
breakers feeding the portion of the loop between the taps must trip, de-energizing the entire
section. When a circuit breaker trips and is not remotely indicated or alarmed, a portion of the
loop may unknowingly remain out of service for an extended period of time even though all
loads remain energized. To prevent this from happening, an alarm point derived from the
overcurrent detection system at both ends of the loop should be installed.

2.4. 2. 4. 2 Open-loop operation

A primary loop system may be operated with one of the series switches in figure 2-4 open.
Fused or non-fused isolation switches, or circuit breakers, may be used in this open-loop
operation. A disadvantage of open-loop operation is that a cable failure will result in the tem-
porary loss of service to some portion of the system.

2.4. 2. 4. 3 Fault isolation

One method for locating a fault in a loop system is the dangerous practice of isolating a
section of the loop and then re-energizing the power source. If the system trips again, another
section is isolated and the power is re-applied. Such action is repeated until the fault is iso-
lated. This method of fault location is not recommended. It is unsafe practice and may cause

IEEE

Std 141-1993

CHAPTER 2

equipment failure as a result of the stress placed on system components and cable insulation.
The reclosing of any power protection device into a known fault in order to locate the faulty
equipment, or to restore the system power without ascertaining the problem, is not
recommended.

2.4. 2. 4. 4 Primary loop system economics

An initial cost saving may be achieved by designing a loop system with isolation switches
instead of circuit breakers. The loop system may be designed with non-fused switches for the
greatest initial cost savings. However, the selection of non-fused switches for isolating an
open loop system provides no overcurrent protection to individual sections of the loop, nor a
reduction of the faulted section. Some portion of the loop will lose power whenever any fault
occurs.

Many times fused isolation switches will be applied in lieu of circuit breakers in a loop sys-
tem. Since it is not possible to selectively coordinate such a system for faults on a closed
loop, the loop should be operated in the open loop mode. The use of fused switches also
introduces the potential for single-phasing in the system. Consequences of single-phasing
may include motor failure, loss of one-third of the lighting, and partial voltage to an addi-
tional one-third of the lighting. Phase failure protection systems are available. If the need for
a form of single-phasing protection is established, some of the cost savings of using fused
switches over circuit breakers is lost.

One possible disadvantage of the system in figure 2-4 is that there is no disconnecting means
ahead of the fuse protecting the transformer. At an additional cost, a disconnect switch would
add convenience for the maintenance of the equipment, and if a problem should occur with
the transformer it can be isolated without opening the loop. Good safety practice for indus-
trial installations will almost always dictate the inclusion of such a switch-fuse combination
or circuit breaker ahead of the transformer.

The economics of the variations in design of primary loop systems can be found in
Chapter 16.

2.4. 2. 5 Secondary selective system

[See figure 2-5(a)]. If pairs of substations are connected through a secondary tie circuit
breaker, the result is a secondary selective system. If the primary feeder or transformer fails,
supply is maintained through the secondary tie circuit breaker. The tie circuit breaker can be
operated in a normally opened or a normally closed position. If operated opened, the supply
is maintained by a manual or automatic opening of the affected transformer’s circuit breaker
followed by a closing of the tie circuit breaker. If the tie is operated closed, the supply is
maintained by the automatic opening of the affected transformer circuit breaker (by reverse
power or reverse current detection); automatic reclosing upon restoration of the faulted cir-
cuit is recommended. In case of the normally opened tie circuit breaker, voltage is maintained
to the unaffected transformer’s circuits. In the case of the normally closed tie, a voltage
depression occurs on the bus until the affected transformer’s circuit breaker opens.

SYSTEM PLANNING

IEEE
Std 141-1993

i ni

1 1 1 1

i X X X

Y Y Y Y

NORMALLY OPEN

J J J Js

f ) f ) T )

4 x x x

Y Y Y Y

(a) Secondary selective system

SPARING

TRANSFORMER

SECONDARY TIE BUS

'YY»« FUTURE

l TRANSFORMER
'+• ADDITION

(b) Sparing transformer scheme

Figure 2-5— Typical configurations load center substations

Normally the systems operate as radial systems. Maintenance of primary feeders, trans-
former, and main secondary disconnecting means is possible with only momentary power
interruption, or no interruption if the stations can be operated in parallel during switching,
although complete station maintenance will require a shutdown. With the loss of one primary
circuit or transformer, the total substation load may be supplied by one transformer. To allow
for this condition, one (or a combination) of the following should be considered:

IEEE

Std 141-1993

CHAPTER 2

a) Oversizing both transformers so that one transformer can carry the total load;

b) Providing forced-air cooling to the transformer in service for the emergency period;

c) Shedding nonessential load for the emergency period;

d) Using the temporary overload capacity in the transformer and accepting the loss of
transformer life.

A distributed secondary selective system has pairs of unit substations in different locations
connected by a tie cable and a normally open disconnecting means in each substation. The
designer should balance the cost of the additional tie disconnecting means and the tie cable
against the cost advantage of putting the unit stations nearer the load center.

The secondary selective system may be combined with the primary selective system to pro-
vide a high degree of reliability. This reliability is purchased with additional investment and
addition of some operating complexity.

In figure 2-5 (a), while adhering to the firm capacity concept, the total load allowed to the sub-
station will be equal to or less than the capability of one transformer or one load side overcur-
rent device, whichever is the most restrictive.

The sparing transformer scheme offers some particular advantages for achieving first contin-
gency capacity in a cost-effective manner in the distribution system. Available transformer
capacity is utilized at a higher level than in a simple redundant configuration (where utiliza-
tion is 50%), and transformers can be readily added to existing substations as the need arises
(if physical space and load requirements allow). In the sparing case [figure 2-5 (b)] the first
contingency capacity is equal to (n- 1 ) transformers or load side overcurrent devices. This
scheme has been successfully used in industry, although there may occasionally be some
personnel reluctant to accept it since the sparing transformer typically remains essentially
unloaded, and the idea of an unloaded unit may seem to represent nonutilization of equipment.

Operations, protection, etc., for configurations shown by figure 2-5(a) and (b) are the same
with two exceptions:

a) Automatic transfer initiated by loss of voltage on a low side bus is not applicable in
the sparing transformer scheme;

b) Feeder overcurrent device fault duty requirements are almost always greater in the
double-end scheme due to the additional motor fault current contribution during the
emergency condition when the tie is closed.

2.4. 2. 6 Secondary spot network

(See figure 2-6.) In this system two or more distribution transformers are each supplied from
a separate primary distribution feeder. The secondaries of the transformers are connected in
parallel through a special type of device, called a network protector, to a secondary bus.
Radial secondary feeders are tapped from the secondary bus to supply utilization equipment.

If a primary feeder fails, or a fault occurs on a primary feeder or distribution transformer, the
other transformers start to feed back through the network protector on the faulted circuit. This

SYSTEM PLANNING

IEEE
Std 141-1993

PRIMARY

FEEDERS

DISCONNECT

SWITCH

DISTRIBUTION

TRANSFORMER

NETWORK

PROTECTOR

SECONDARY BUS

SECONDARY

FEEDERS

TO LOAD

Figure 2-6— Secondary spot network

reverse power causes the network protector to open and disconnect the supply circuit from
the secondary bus. The network protector operates so fast that there is a minimal exposure of
secondary equipment to the associated voltage drop.

The secondary spot network is the most reliable power supply for large loads. A power inter-
ruption can only occur when there is a simultaneous failure of all primary feeders or when a
fault occurs on the secondary bus. There are no momentary interruptions caused by the oper-
ation of the transfer switches that occur on primary selective, secondary selective, or loop
systems. Voltage sags caused by large transient loads are substantially reduced.

Networks are expensive because of the extra cost of the network protector and duplication of
transformer capacity. In addition, each transformer connected in parallel increases the short-
circuit-current capacity and may increase the duty ratings of the secondary equipment. This
scheme is used only in low-voltage applications with a very high load density. Also, it
requires a special bus construction to reduce the potential of arcing fault escalation.

The packaged protector used by the utilities and preferred by some industrial users is not in
itself adequately protected to meet the National Electrical Code (NEC) (ANSI/NFPA 70-
1993) requirements, and also should not be regarded as equivalent to draw-out switchgear
from a safety standpoint. Either supplementary protection should be added or, preferably,
standard switchgear should be used, suitable for the purpose with proper protective relaying.

2.4. 2. 7 Ring bus

(See figure 2-7.) The ring bus offers the advantage of automatically isolating a fault and
restoring service. Should a fault occur in Source 1, Devices A and D would operate to isolate

IEEE

Std 141-1993

CHAPTER 2

the fault while Source 2 would feed the loads. A fault anywhere in the ring results in two
interrupting devices opening to isolate the fault.

Figure 2-7— Ring bus system

The ring bus scheme is often considered where there are two (2) or more medium voltage
(i.e., 4.16, 4.8, or 13.2/13.8 kV) distribution services to the facility and the utmost in flexibil-
ity and switching options are desired. Care must be taken that allowable fault duties are not
exceeded with closed bus tie breaker operation in this scheme.

Manual isolating switches are installed on each side of the automatic device. This allows
maintenance to be performed safely and without interruption of service. This will also allow
the system to be expanded without interruption.

2.4.3 Equipment locations

The engineer, in cooperation with process personnel, selects locations for distribution trans-
formers and major utilization voltage switching centers. In general, the closer the transformer
to the load center of the area served, the lower the distribution system cost.

2.4.4 Plant utilization voltage

Select the best plant utilization voltage for the various system voltage levels. The most com-
mon utilization voltage in United States industrial facilities is 480 V. Other voltage levels
depend upon motor rating and size, utility voltage available, total load served, potential
expansion requirements, voltage regulation, and cost. Chapter 3 is a guide for correct voltage
selection. The system should be capable of providing power to all equipment within pub-
lished voltage limits under all normal operating conditions and meeting possible future loads.
Additional voltage considerations will include flicker restrictions created due to large motor

SYSTEM PLANNING

IEEE
Std 141-1993

starting and the subsequent voltage drop during starting and restrictions placed on the user by
the utility to prevent disturbances to their system when starting the user’s large motors. Par-
ticular care should be taken when served from utility area distribution substations, since these
are typically higher impedance systems having lower fault currents. The starting of large
motors or other short-circuit type loads (i.e., welding, arc furnaces, etc.) can result in a short-
term voltage sag or fluctuation elsewhere on the feeder.

2.4.5 Primary utility supply service

When it is anticipated that a new service or change in the existing utility supply is required,
sufficient time should be allowed in the planning cycle to permit proper negotiations with the
utility. The negotiations with the utility should precede the time scheduled for the specifica-
tion. procurement, manufacture, installation of facilities, and commissioning. The negotia-
tions with the utility should culminate in a contract so that utility engineering, design, and
construction may begin in parallel with the customers efforts.

The industrial facility may be required to pay the cost of the change in service or the addi-
tional utility facilities.

It should be recognized that utility policy may require a contract for service/facilities before
any engineering, right-of-way acquisition, environmental impact statements, or filing of per-
mit applications.

Experience indicates that a utility may require 18 to 24 months to install a new substation or
distribution/transmission line. This schedule usually begins after the contract is executed.

Refer to Chapter 1 5 for additional utility planning and design criteria required to provide an
industrial primary supply substation.

At every step, whether for an all-new plant or for an existing plant, plans for the future are
absolutely necessary. When this is done properly, subsequent increases in plant load can be
accommodated by adding capacity to the initial system instead of necessitating a redesign of
the whole primary system. In short, no plant primary supply and distribution system should
ever be designed in a manner that will make it difficult or impossible to expand its capacity.

More important than the timing of capital investment is the need to permanently allocate
space for installing power supply and distribution apparatus that may be required for the ulti-
mate plant development at the site. Thus, it is clear that an estimate of the ultimate demand is
necessary in order to establish the number and nature of future required facilities.

Experience has shown that when insufficient space is allocated for expanding either the high-
voltage outdoor substation or the indoor main distribution switchgear, there is a tendency to
compromise safety, reliability, and convenience. The latter usually translates into a deprecia-
tion of reliability because space for equipment removal or maintenance, or both, is sacrificed.
Therefore, it usually becomes necessary to remove additional equipment in order to repair or
replace another piece of apparatus that has failed.

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Std 141-1993

CHAPTER 2

Figure 2-8 is presented to illustrate some of the considerations that are a necessary part of
planning the power supply. Although the example suggests a totally new plant, similar for-
ward planning is equally necessary at an existing facility before the demand exceeds the firm
supply capacity.

Figure 2-8— Power supply planning considerations

By using various combinations of systems, the engineer can design a system to meet the load
requirements. It may be necessary to design a system that can be expanded for future growth.
As an example, the engineer can start with a radial system supplied at 13.8 kV from the util-
ity. (See figure 2-1.) As the load at the site grows, the engineer can convert to a double-ended
substation, such as is shown in figure 2-5(a). At the time of a major expansion and when the
load requires additional power, the engineer can go to a ring bus. (See figure 2-7.) This ring
bus, through transformation, can supply an intermediate distribution system at the original
utility voltage of 13.8 kV. With proper planning and system selection, the engineer can have
enough flexibility to meet any load requirement.

Selecting the number of main distribution buses and the method of interconnecting them
depends upon many factors such as the sizes of the immediate and ultimate plant loads, the
primary distribution voltage, the availability of suitable supply lines, and other factors relat-
ing to the utility system.

Figure 2-9 is presented for the purpose of illustrating a number of main primary substation
configurations that can be considered for use. Figure 2-9 demonstrates that there are many
ways to develop the main primary distribution configuration while meeting specific require-
ments or constraints.

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EXPANSION ALTERNATES

NEW LIMITS NEW CONFIGURATION

(a)

2 OF 4 BUSES OR
1 OF 2 TRANSFORMERS

INITIAL CONFIGURATION

LIMITS:

1 OF 2 BUSES OR
1 OF 2 TRANSFORMERS

1 OF 2 BUSES OR

2 OF 3 TRANSFORMERS

Figure 2-9— Typical main primary distribution arrangements

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The two-bus arrangement (figure 2-9), shown as the initial configuration, represents the low-
est cost arrangement. To maximize the firm capability of this arrangement requires that the
thermal ratings of the supply (transformer), the main circuit breaker, and the switchgear main
bus bar be equal. While later discussions will more thoroughly consider specific ratings, pre-
cisely matching all of these thermal capacities is extremely difficult and is rarely achieved.
Therefore, the usual occurrence is one in which either the supply transformer or the switch-
gear, the main circuit breaker, or the bus bars are limiting.

Figure 2-9 suggests that the initial sizing of switchgear should be compatible with future
expansion. Future in this case is intended to reflect the useful life of well-maintained switch-
gear.

Figure 2-9(a) depicts one method for expanding the system where transformer size is
increased and initial switchgear is augmented. This method, when used to increase the useful
life of undersized switchgear, may require operation under somewhat restrictive conditions so
the circuit breaker short-circuit ratings are not exceeded.

Where a third transformer (supply) is possible and feasible, there are three widely used
schemes as shown by figure 2-9(b), (c), and (d). The sparing transformer scheme of figure
2-9(d) is usually the least attractive because switchgear limits are unchanged. Figure 2-9(c)
represents the most commonly installed scheme, but this scheme is nearly always capacity-
limited by switchgear even when current-limiting reactors are installed in bus tie circuits.
Even so, 2-9(c) is usually the preferred configuration because reactive losses are incurred
only when the bus loading is unbalanced and during emergency periods. Figure 2-9(b) is
more costly than either 2-9(c) or 2-9(d), and its capacity is almost always limited by the
transformer rating, particularly when duplex reactors are installed between transformers and
main disconnecting devices to limit circuit breaker short-circuit duty.

Substation expansion is also possible by exchanging initially installed transformers for larger
units. This is rarely done in instances where the plant owns the supply transformers. How-
ever, when transformers are supplied by the utility and when the initial transformers can be
utilized by the utility, it is frequently more economical to exchange units than to add a third
unit and all of the associated switching apparatus. Usually when a utility exchanges trans-
formers, the customer receives credit for the retired equipment on the basis of replacement
cost new less depreciation, although this is also subject to negotiation if there are no clear
utility policies. Therefore, it may be financially attractive to begin a supply substation with
two 15/20/25 MVA units and later exchange them for two 30/40/50 MVA units. However, in
order to be technically feasible, the main plant primary switchgear must be rated to handle
the higher load current as well as the higher short-circuit duty due to the larger transformers.
The station must originally be designed for such additions, including consideration for
needed clearances, structural steel requirements, foundations, and equipment installations
and removal spaces.

When expanding an existing plant, determine if all the existing equipment is adequate by
checking ratings: voltage, interrupting capacity, short-circuit withstand, momentary capabil-
ity, switch close and latch, and continuous current. Selective coordination of protective

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device trip characteristics may require modifications to the existing relaying/fusing to coordi-
nate with the new design and ensure that appropriate margins of safety are maintained.

2.4.6 Generation

Determine whether parallel, standby, or emergency plant generation will be included. Tech-
nical and tariff issues must be included in the initial planning so as to prevent having to
modify or reconstruct certain parts of the plant supply and distribution system to accom-
modate generation.

2.4.6. 1 Technical issues

The following technical electrical issues must be reviewed during the planning stages:

a) Number of generators and ratings

1) Generator’s output in kilovoltamperes

2) Generator’s voltage

3) Generator’s rated full-load current

4) Type of generator

5) Generator’s rated power factor

6) Generator’s reactances on generator kilovoltamperes base, including synchro-
nous, transient, and subtransient reactances and time constants to produce gen-
erator decrement curves for protective coordination

7) Generator’s transformer requirements, including size/rating in kilovoltamperes,
impedance, and base connection

8) Relaying and protection of generator

b) Metering

c) Voltage regulation

d) Synchronizing

e) Grounding

f) Cost

g) Operation and loading of the generator on a scheduled basis

h) Maintenance requirements

i) Largest motor to be started with generator running

j) Available fault current (three-phase and single-phase to ground) from the generator to
the plant system

k) Utility’s interconnection and parallel operating conditions including relaying and
protective-device requirements

Consideration should be given to the load imposed on the generator when groups of motors
are started instead of one large motor. These groups of motors may be arranged for staggered
starting so that a smaller generator can be specified.

The complete design must be coordinated with the utility if parallel operation with the util-
ity’s system is anticipated. With some utility tariffs, it may be advantageous to utilize plant
generation to decrease plant base load or to shave peak load.

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2.4.6. 2 Rate and financial considerations

The following conditions must be evaluated carefully since the installation of parallel genera-
tion will affect the economics of operation and the user’s substation design:

a) Utility’s charges, including kilowatt and kilovoltampere demand (based on maximum
demand), variable or kilowatthour charges, such as fuel (usually in cents/kWh), and
other associated costs, such as power-factor metering. These charges are usually
determined from an analysis of the approved, applicable, utility rate schedules. The
availability of special or incentive rates should also be investigated (i.e., deferred
cogeneration, economic development, peak shaving, and interruptible rates);

b) Utility’s cogeneration supplemental power, back-up, and maintenance tariffs;

c) Conditions for electric load displacement by the customer and for customer-supplied
capacity (including dispatching requirements) and energy delivery to the utility;

d) Customer’s load relative to the cogeneration size, especially during peak and mini-
mum (nonproductive) load periods.

Of particular significance are the following:

a) Planned means of connecting the cogenerator to the user’s system;

b) Subsequent impact of fault current from the unit on the user’s system;

c) Utility’s special relaying and protective-device requirements. Particular care should
be exercised if automatic recalling on generator operation is considered in order to
avoid creating any potential unsafe or dangerous conditions.

2.4.7 Single-line diagram

A complete one-line or single-line diagram, in conjunction with a physical plan of the instal-
lation, should present sufficient data to plan and evaluate the electric power system. Figures
4-10 and 5-19 in Chapters 4 and 5 represent single-line diagrams containing some of the
information required for system-protection design and fault-current analysis.

The basic function of the single-line diagram is to convey information concerning the power
system, including the overall scheme as well as details of each element of the plant supply
and distribution system. Symbols commonly used in single-line diagrams are defined in IEEE
Std 315-1975.

The following items should be shown on the single-line diagram or other documentation.

2.4.7. 1 Utility supply system

a) Utility line supply voltage (34.5/46/1 15/138/161 kV, etc.);

b) High-voltage protective devices and switches, including circuit switchers, motor-
operated air break switches, nonload break switches, etc. The nominal operating
mode of all such devices should be indicated (i.e., NO/NC for normally open/nor-
mally closed, respectively), together with the nominal continuous-current ratings and
interrupting or momentary closing and latching short-circuit current ratings;

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c) Maximum and minimum three-phase and phase-to-ground available short-circuit
duty (megavoltamperes and symmetrical current), and system equivalent impedances
(three-phase and single-phase-to-ground, indicating base used— typically 100 MVA);

d) Types of relays, ANSI identification, relay location, and calibration settings for all
high-voltage protective devices;

e) Primary supply cables (if used) including size, capacity, shielding, insulation, instal-
lation design (duct banks/direct burial, etc.), number of conductors, nominal ampac-
ity (amperes and kilovoltamperes/megavoltamperes) and bases, etc.

2.4. 7. 2 Primary utility supply transformers

a) Nameplate rating(s) (kilovoltamperes and kilovolts) and temperature rise;

b) Rating in kilovoltamperes for continuous summer duty;

c) High-voltage winding voltage taps and winding connection (delta/wye);

d) Low-voltage winding voltage taps and winding connection (delta/wye);

e) Load tap changer— voltage range and percent steps;

f) In-line voltage regulator (if separate) ratings;

g) Impedance and kilovoltamperes base;

h) Grounding scheme and ohmic value of neutral resistor(s) if used; show connections;

i) Surge arrestors and capacitors (show switching if switched), and connections;

j) Metering of utility supply;

k) Primary protective devices when primary supply is supplied from distribution sys-
tem. Include ratings (megavoltamperes, amperes), nominal operational mode, and
protective devices with coordination settings.

2.4.7.3 Incoming primary: Cable or bus to main switchgear from supply transformers

a) Indicate type (bus, cable, etc.), type of insulation, continuous-current rating (ampac-
ity), physical support, and installation design (underground cable in duct bank, bus,
overhead cable in tray, tray size, etc.);

b) Nominal maximum current rating(s) and basis.

2.4. 7. 4 Main switchgear

a) Manufacturer(s), type, model, current rating, megavoltamperes class, symmetrical
interrupting current rating, and asymmetrical momentary/closing-and-latching cur-
rent rating for main, tie, and feeder devices;

b) Indicate nominal operational mode for all switchgear and disconnecting devices;

c) Ampacity of bus.

2.4. 7. 5 Primary feeder cables

a) Number of feeders;

b) Cable insulation and type;

c) Installation design (conduit. Interlocked Armored Cable [1AC] in tray, size of tray,
number of cables in tray, etc.);

d) Nominal maximum current rating and basis;

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e) Cable size and number of cables per phase;

f) Year of installation.

2.4. 7. 6 Primary distribution system

a) Include primary switching, fusing, other protective devices, transformer connections,
ratings, system grounding, nominal loading (kilovoltamperes and amperes), and low-
voltage protective-device arrangement for unit substation and load centers. Indicate
each protective device’s continuous-current rating, symmetrical interrupting current
and asymmetrical momentary or closing-and-latching current rating, manufacturer,
type, and model identification. Indicate tap settings on all primary transformers;

b) Indicate bus ratings in amperes;

c) Identify major load centers and indicate general electrical configuration;

d) Identify nominal loads in kilovoltamperes and amperes on unit substations, trans-
formers, and load centers;

e) Identify and show all major medium-voltage loads and motors, including associated
transformers and all other major, significant and identifiable loads, such as motor
loads on motor control centers, large press and other motor or drive loads, dedicated
lighting loads, arc furnaces, induction furnaces, special purpose loads, such as data
processing and computer applications, welding loads, powerhouse loads, including
waste treatment, air compressor loads, etc.

2.4. 7. 7 Relay and protective device coordination

The relay coordination and protective-device settings should be on separate documentation
that forms a part of the single-line diagram. Show for utility medium-voltage supply, primary
distribution system, and low-voltage or secondary distribution system.

2.4. 7. 8 Normal operation mode of switching and isolation devices

Indicate normal operation mode of all switching, isolation, and protective devices.

2.4. 7. 9 Future space considerations

Primary main switchgear. Indicate space for expansion of primary feeder overcurrent devices
in switch house or available cubicles for such expansion.

2.4.7.10 Running (operating) motor loads

An integral part of the single-line diagram is the summary of running motor loads in the
plant. This information is important for short-circuit and protective-device coordination.

At a minimum, the following information should be obtained:

a) By size category for each 480 V transformer (less than 50 hp; 50 hp and larger);

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IEEE
Std 141-1993

b) List individual medium-voltage motors (e.g., 2400 V, 4160 V, 4800 V, 6900 V and
13800 V systems), including horsepower/kilowatt, revolutions per minute, and type
(induction, synchronous);

c) Include powerhouse motors (chillers, compressors, etc.);

d) Indicate all solid-state/SCR-controlled variable-speed ac/dc-converter motor drives.
(These may not contribute to fault current.)

2.4.7.11 Capacitor banks

Medium- and low-voltage capacitor bank installations should be shown on the single-line dia-
gram together with connections and switching configuration and ratings (voltage, kilovar, etc.).

a) Location and rating of each capacitor bank installed;

b) Switched or permanently connected? If switched, design criteria (if available), and
details on control scheme;

c) Capacitors status (connected?/working?).

The actual drawing should be kept as simple as possible. It is a schematic diagram and need
not show geographical relationship. Duplication should be avoided.

2.4.8 Short-circuit analysis

Calculate short-circuit currents available at all system components. Chapter 4 provides a
detailed guide to making these calculations. A short-circuit evaluation should always be per-
formed if changes are made to the primary utility supply system that may affect available
fault current. Such changes can include, but are not limited to, the following:

a) High-voltage conversion or upgrading;

b) Replacement of lower capacity primary transformers with higher capacity or lower
impedance transformers;

c) Additional primary service from alternate sources;

d) Operation in a different mode that increases available short-circuit current, such as
changing to a closed bus tie operation from a normally open configuration or the
installation of a large generator on the primary distribution system.

Additionally, significant changes in motor loads within the facility may affect available fault
current.

Normal, emergency, and standby system operating configurations should be included in the
analysis.

As a guide, a short-circuit analysis should be performed at least every five to ten years if no
major system changes have occurred that dictate a new study.

2.4.9 Protection and protective-device coordination

The protection and protective-device coordination evaluation should always be performed in
conjunction with a short-circuit evaluation. This should be performed whenever there are
major changes made to the utility primary electric supply that can affect available fault cur-
rent or other major system changes that can affect system operation and coordination. Using

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CHAPTER 2

the data presented in Chapter 5, design the required protective systems. System-protection
design must be an integral part of the total system design and not be superimposed on a
system later.

Coordination of critical loads, such as uninterruptible power supplies (UPS) with their fast-
acting overcurrent devices to protect electronic devices, should be included in the analysis.

2.4.10 Communications

Any plan for the protection of a plant must include a reliable communication system, such as
a self-contained system of telephones, alarms, etc., which may include modern radio and tele-
vision equipment, or by a joint system tied into the existing communication services.

Fire and smoke alarm circuits, whether self-contained or connected to municipal alarm sys-
tems, should be installed to minimize the effect of faults and changes in buildings or plant
operations. Circuits should be arranged to provide easy means of testing and to isolate por-
tions of the system without interfering with the remainder of the system.

Security guard circuits, including television and radio equipment, are used in many plants for
the purpose of providing a ready means for the individual security guard to report unusual
circumstances to the supervisor without delay. Such systems are frequently combined with
public-address paging systems and other alarm methods.

Annunciator systems are available for alerting operations to abnormal situations in critical
areas. The operator can dispatch personnel to investigate the malfunction or disorder or take
corrective action.

2.4.11 Maintenance

Electric equipment must be selected and installed with attention to adequacy of performance,
safety, and reliability. To preserve these features, a maintenance program must be established
and tailored to the type of equipment and the details of the particular installation. Some items
require daily attention, some weekly, and others can be tested or checked annually or less
frequently.

Requirements of a maintenance program should be incorporated in the electrical design to
provide working space, easy access for inspection, facilities for sampling and testing, and dis-
connecting means for protection of the workmen, lighting, and standby power. The mainte-
nance program should have the following objectives.

2.4.11.1 Cleanliness

Dirt and dust accumulation affects the ventilation of equipment and causes excess heat,
which reduces the life of the insulation. Dirt and dust also build up on the surfaces of insula-
tors to form paths for leakage that may result in arcing faults. Insulated surfaces should be
cleaned regularly to minimize these hazards.

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2.4.11.2 Moisture control

Moisture reduces the dielectric strength of many insulating materials. Unnecessary openings
should be closed and necessary openings should be baffled or filtered to prevent the entrance
of moisture, especially light snow. Also, even though equipment is adequately housed and
indoors, condensation from weather changes should be minimized by supplying heat, usually
electric, to the enclosure interiors. From 5-7.5 W/ft 2 of external enclosure surface is usually
effective when placed at the bottom of each space affected. A small amount of ventilation
outdoors is necessary even with heating to avoid condensation damage and insulation failure.

2.4.11.3 Adequate ventilation

Much electric equipment is designed with paths for ventilating air to pass over insulating sur-
faces to dissipate heat. Filters must be changed, fans inspected, and equipment cleaned often
enough to keep such ventilating systems operating properly.

2.4.11.4 Reduced corrosion

Corrosion destroys the integrity of equipment and enclosures. As soon as evidence of
corrosion is noted, action should be taken to clean the affected surfaces and inhibit future
deterioration.

2.4.11.5 Maintenance of conductors

Conducting surfaces reveal problems caused by overheating, wear, or misalignment of con-
tact surfaces. These conditions should be corrected by tightening bolts, correcting excessive
operations, aligning contacts, or whatever action is necessary.

2.4.11.6 Regular inspections

Inspections should be scheduled on a regular basis depending on equipment needs and pro-
cess requirements. External inspection can often be made and reveal significant information
without process shutdown. However, a complete inspection will require a shutdown. Plans for
repairs should be based on such inspections so that necessary manpower, tools, and replace-
ment parts will be available as needed during the shutdown.

2.4.11.7 Regular testing

Performance of protective devices depends on the accuracy and repeatability of the sensing
devices and the integrity of the control circuits. Periodic tests of such devices as well as of the
dielectric strength of insulating systems and the color and acidity of the insulating oils, etc.,
will reveal deteriorating conditions that cannot be determined by visual inspection. Necessary
adjustments or corrections can be made before failure occurs.

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2.4.11.8 Adequate records

An organized system of inspection records, maintenance, tests, and repairs provides a basis
for trouble-shooting, predicting equipment failures, and selecting future equipment.

2.4.11.9 Codes and standards

Throughout the design, adherence to all applicable national and local laws, codes, and stan-
dards is required.

2.5 Power system modernization and evaluation studies/programs

The following circumstances, occurring individually, or in combination, suggest that a power
system analysis and evaluation may be required to ensure continued safe and reliable power
system operation. These aspects should be continually monitored to ensure that system com-
ponents and operation are adequately maintained over time.

a) Production changes. Major production program may be initiated that could impact
the primary electric power system supply and/or distribution system.

b) Load growth. Rapid load growth due to production increases. Typically a 10-15%
load growth increase projected over a relatively short time period (i.e., 1 to IV 2 years)
is cause for further evaluation.

c) Modifications to applicable electrical laws and codes

d) Primary distribution system and load center substation equipment capacity limits.
Primary supply and/or transformation equipment, primary bus, primary switchgear,
primary feeders, or load center substations may be nearing their firm/first contin-
gency capacity or may be already exceeding that capacity and additional equipment
or load rebalancing is required. These concerns can occur over time as routine prod-
uct and process enhancements are incorporated into production operations.

e) Power factor problems. The first notice of a power factor problem usually occurs
when there is a power factor penalty charge included in the electric utility bill. It
should be noted that all utilities do not have a power factor penalty. Symptoms of a
power factor problem can include blown capacitor fuses, inoperable capacitor banks,
low voltage, overloaded primary feeders, etc.

f) Harmonic problems. Symptoms of harmonic problems include blown power factor
correction capacitor fuses, a reduction in plant power factor, motor and transformer
heating and/or failure, and possibly unexplainable operation malfunctions of process
controls, especially timing problems in electronic equipment. Typical causes of har-
monic problems include the application of power electronics and other solid-state
power control devices for plant processes combined with power factor correction
capacitors, creating harmonic resonance situations.

g) Power quality problems. Power quality problems may be encountered with the
primary utility supply, within the plant primary and/or secondary distribution sys-
tems, with particular plant equipment, or with all systems. Frequent voltage sags,
surges, transients, interruptions, or other utility system disturbances may affect plant

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production operations. Such system disturbances can also be caused by in-plant
devices that generate disturbances in their operation. In some cases, equipment may
create system disturbances by its operation that in turn may affect its operations.
Excessive interruptions or equipment shutdown may then be encountered on the spe-
cibc pieces of in-plant equipment or systems.

h) Welding processes. A new or additional welding process may be installed that causes
problems with existing welding operations or process control schemes may be modi-
fied resulting in unacceptable operations. Symptoms include low voltage, blown
fuses, poor weld quality, component overheating and/or failure.

i) Deterioration of primary equipment. Primary equipment can become obsolete over
time; outdated due to age or condition; present safety or environmental concerns (i.e.,
toxic, hazardous, or containment provisions); or equipment can become overdutied,
unsafe, inoperable, or approach the end of its useful life. Electrical system compo-
nent response or performance over time can then be affected, suggesting that equip-
ment be replaced or upgraded to ensure safety and system operating reliability.
Conditions can usually be determined by inspection and are often obvious, although a
detailed, professional inspection is important to verify the plant’s findings.

Power system evaluation programs all involve the identification and resolution of safety
related concerns, inadequate facility or equipment capacity concerns, and the implementation
of safety improvements to maintain or enhance safety and operating reliability of the plant
power system.

These evaluations perform two fundamental, extremely useful functions in the overall
process of evaluating and maintaining safe and reliable power system. First, they provide a
documented engineering concept or basis for the required system changes needed to resolve a
particular problem, situation, or concern. Second, they provide the engineering cost basis for
the required changes so that adequate funding can be estimated, supported, sought, and
allocated.

The engineering activities associated with this type of evaluation are quite challenging and
often are not well understood. Consequently, this type of work is sometimes performed inad-
equately or incompletely. This problem seems to occur primarily because the engineering
task is not necessarily well defined, since defining the work and determining the conditions
and the economical yet practical requirements are really the engineering assignment. This
type of work requires the application of experience and engineering concepts and not a sim-
ple application of known design rules.

2.5.1 Criteria for engineering studies and evaluations

Criteria for these studies should be developed in a conceptual format. The criteria should
define the known or identified problems, concerns, or circumstances that are to be addressed
in the evaluation of the existing power system. The specific system concept requirements that
require identification, evaluation, and resolution should be described, including supply/distri-
bution system concept development, system analysis, system/equipment evaluations, and
general schedule requirements for the projects.

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Conceptual engineering study work areas may typically include the following types:

a) Evaluation of the adequacy of power system equipment, including the testing and
coordination of protective devices

b) Analysis for the expansion/conversion of the medium-voltage primary supply

c) Plant distribution system life-extension and modernization evaluation and alterna-
tives

d) Load-flow analysis

e) Network (including welding system) studies to define available fault current, voltage
drops, and load flow

f) Motor- starting studies

g) Short-circuit analysis and protective-device coordination

h) Power-factor improvement programs including evaluation of harmonic resonance
concerns and/or need for tuned-filter apparatus

i) Specifications, standards, and guidance development

j) PCB -equipment-replacement programs

k) Switching-transients analysis

l) Harmonic analysis of the power system

m) Reliability analysis

n) Removal and construction work sequence for modernization projects to ensure that
the work is feasible during production operations and to establish a cost baseline

o) Cable-ampacity analysis

p) Ground-mat studies

The study criteria should also define the applicable standard specifications that will apply to
the work when performed. These specifications should be considered in developing and eval-
uating alternatives, in performing the study, and when preparing any cost estimates for
concept projects.

2.6 References

This standard shall be used in conjunction with the following publications:

ANSI/NFPA 70-1993, National Electrical Code. 2

ANSI/NFPA 70B-1990, Recommended Practice for Electrical Equipment Maintenance.

IEEE P277, Recommended Practice for Cement Plant Power Distribution (Dl.l, 6/9/88). 3

IEEE Std 315-1975 (CSA Z99-1975) (Reaff 1989), IEEE Standard Graphic Symbols for
Electrical and Electronics Diagrams (ANSI). 4

“NFPA publications are available from Publication Sales, National Fire Protection Agency, 1 Batterymarch Park,
P.O. Box 9101, Quincy. MA 02269-9101, USA.

4 This IEEE authorized standards project is available from the Sales Dept., IEEE Service Center, 445 Hoes Lane, Pis-
cataway.NJ 08855-1331.

4 IEEE publications are available from the Institute of Electrical and Electronics Engineers, Service Center. 445 Hoes
Lane, Piscataway, NJ 08855-1331, USA.

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Std 141-1993

IEEE Std 493-1990, IEEE Recommended Practice for the Design of Reliable Industrial and
Commercial Power Systems (IEEE Gold Book) (ANSI).

2.7 Bibliography

[Bl] Bjornson, N. R., “How Much Redundancy and What It Will Cost,” IEEE Transactions
on Industry and General Applications, vol. IGA-6, pp. 192-195, May/June 1970.

[B2] Gannon, P. E., “Cost of Interruptions; Economic Evaluation of Reliability,” IEEE Indus-
trial and Commercial Power Systems Technical Conference, Los Angeles, May 10-13, 1976.

[B3] Heising, C. R., “Examples of Reliability and Availability Analysis of Common Low-
Voltage Industrial Power Distribution Systems,” IEEE Industrial and Commercial Power Sys-
tems Technical Conference, Los Angeles, May 10-13, 1976.

[B4] Heising, C. R., “Reliability and Availability Comparison of Common Low- Voltage
Industrial Power Distribution Systems,” IEEE Transactions on Industry and General Appli-
cations, vol. IGA-6, pp. 416^-24, Sept. /Oct. 1970.

[B5] IEEE Committee Report, “Report on Reliability Survey of Industrial Plants, Parts I— HI,”
IEEE Transactions on Industry Applications, vol. IA-10, pp. 213-252, Mar./Apr. 1974.

[B6J Beeman, E. D., Industrial Power System Handbook. New York: McGraw-Hill Book
Company, Inc., 1955.

[B7| Johnson, G. T., and Breniman, P. E., “Electrical Distribution System for a Large Fertil-
izer Complex,” IEEE Transactions on Industry and General Applications, vol. IGA-5,
pp. 566-577, Sept./Oct. 1969.

[B8] McFadden, R. H., “Power-System Analysis: What It Can Do for Industrial Plants,” IEEE
Transactions on Industry and General Applications, vol. IGA-7, pp. 181-188, Mar./Apr.
1971.

[B9J Paten, A. D., “Fundamentals of Power System Reliability Evaluation,” IEEE Industrial
and Commercial Power Systems Technical Conference, Los Angeles, May 10-13, 1976.

[B 10J Regotti, A. R., and Trasky, J. G., “What to Look for in a Low- Voltage Unit Substation,”
IEEE Transactions on Industry and General Applications, vol. IGA-5, pp. 710-719, Nov./
Dec. 1969.

[Bll| Shaw, E. T., Inspection and Test of Electrical Equipment. Pittsburgh, PA: Westinghouse
Electric Corporation, Electric Service Division, Pub. MB3051, 1967.

[B12] Yuen, M. H., and Knight, R. L., “On-Site Electrical Power Generation and Distribution
for Large Oil and Gas Production Complex in Libya,” IEEE Transactions on Industry and
General Applications, vol. IGA-7, pp. 273-289, Mar./Apr. 1971.

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Chapter 3

Voltage considerations

3.1 General

An understanding of system voltage nomenclature and the preferred voltage ratings of distri-
bution apparatus and utilization equipment is essential to ensure proper voltage identification
throughout a power distribution system. The dynamic characteristics of the system need to be
recognized and the proper principles of voltage control applied so that satisfactory voltages
will be supplied to all utilization equipment under all normal conditions of operation. Consid-
eration should be given for transient and momentary voltage variations to ensure appropriate
performance of utilization equipment.

3.1.1 Definitions

The following terms and definitions, quoted from ANSI C84. 1-1989, 1 are used to identify the
voltages and voltage classes used in electric power distribution.

3.1. 1.1 System voltage terms

Note that the nominal system voltage is near the voltage level at which the system normally
operates. To allow for operating contingencies, systems generally operate at voltage levels
about 5-10% below the maximum system voltage for which system components are designed.

3.1.1.1.1 system voltage: The root-mean-square phase-to-phase voltage of a portion of an ac
electric system. Each system voltage pertains to a portion of the system that is bounded by
transformers or utilization equipment. (All voltages hereafter are root-mean-square phase-to-
phase or phase-to-neutral voltages.)

3.1.1.1.2 nominal system voltage: The voltage by which a portion of the system is desig-
nated and to which certain operating characteristics of the system are related. Each nominal
system voltage pertains to a portion of the system that is bounded by transformers or utiliza-
tion equipment.

3.1.1.1.3 maximum system voltage: The highest system voltage that occurs under normal
operating conditions, and the highest system voltage for which equipment and other compo-
nents are designed for satisfactory continuous operation without derating of any kind. In
defining maximum system voltage, voltage transients and temporary overvoltages caused by
abnormal system conditions, such as faults, load rejection, and the like, are excluded. How-
ever, voltage transients and temporary overvoltages may affect equipment operating perform-
ance and are considered in equipment application.

'information on references can be found in 3.12.

IEEE

Std 141-1993

CHAPTER 3

3.1.1.1.4 service voltage: The voltage at the point where the electric system of the supplier
and the electric system of the user are connected.

3.1.1.1.5 utilization voltage: The voltage at the line terminals of utilization equipment.

3.1.1.1.6 nominal utilization voltage: The voltage rating of certain utilization equipment
used on the system.

3. 1.1. 2 System voltage classes

3.1.1.2.1 low voltage: A class of nominal system voltages less than 1000 V.

3.1.1.2.2 medium voltage: A class of nominal system voltages equal to or greater than
1000 V and less than 100 000 V.

3.1.1.2.3 high voltage: A class of nominal system voltages equal from 100 000 V to
230 000 V.

3.1.2 Standard nominal system voltages for the United States

These voltages and their associated tolerance limits are listed in ANSI C84. 1-1989 for volt-
ages from 120-230 000 V and in ANSI C92. 2-1987 for voltages above 230 kV nominal.
Table 3-1, reprinted from ANSI C84. 1-1989 and containing information from ANSI C92.9-
1987, provides all the standard nominal system voltages and their associated tolerance limits
for the United States. Preferred nominal system voltages and voltage ranges are shown in
boldface type while other systems in substantial use that are recognized as standard voltages
are shown in regular type. Other voltages may be encountered on older systems but they are
not recognized as standard voltages. The transformer connections from which these voltages
are derived are shown in figure 3- 1 .

Two sets of tolerance limits are defined: range A, which specifies the limits under most oper-
ating conditions, and range B, which allows minor excursions outside the range A limits.

3.1.3 Application of voltage classes

a) Low- voltage class voltages are used to supply utilization equipment.

b) Medium-voltage class voltages are used for subtransmission and primary distribu-
tion. Medium voltages often supply distribution transformers which step the medium
voltage down to low voltage to supply utilization equipment. Medium voltages may
also supply distribution substations that transform the voltage from a higher to a
lower voltage in the medium- voltage class. Medium voltages of 13 800 V and below
are also used to supply utilization equipment such as large motors (see 3.5.2,
table 3-8).

c) High-voltage class voltages are used to transmit large amounts of electric power
between transmission substations. Transmission substations located adjacent to gen-
erating stations step the generator voltage up to the transmission voltage. Other trans-
mission substations transform the high voltage down to medium voltage for

Table 3-1 —Standard nominal system voltages and voltage ranges

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

IEEE

Std 141-1993

CHAPTER 3

Table 3-1 (Continued)

NOTES FOR TABLE 3-1

a — Three-phase, three-wire systems are systems in which only the three-phase conductors are carried out
from the source for connection of loads. The source may be derived from any type of three-phase trans-
former connection, grounded or ungrounded. Three-phase, four-wire systems are systems in which a
grounded neutral conductor is also carried out from the source for connection of loads. Four-wire sys-
tems in this table are designated by the phase-to-phase voltage, followed by the letter Y (except for the
240/120 V delta system), a slant line, and the phase-to-neutral voltage. Single-phase services and loads
may be supplied from either single-phase or three-phase systems. The principal transformer connections
that are used to supply single-phase and three-phase systems are illustrated in figure 3-1.
b — The voltage ranges in this table are illustrated in ANSI C84.1-1989, Appendix B.
c — For 120-600 V nominal systems, voltages in this column are maximum service voltages. Maximum
utilization voltages would not be expected to exceed 125 V for the nominal system voltage of 120, nor
appropriate multiples thereof for other nominal system voltages through 600 V.
d — A modification of this three-phase, four-wire system is available as a 120/208Y-volt service for
single-phase, three-wire, open-wye applications.

e — Certain kinds of control and protective equipment presently available have a maximum voltage limit
of 600 V ; the manufacturer or power supplier, or both, should be consulted to ensure proper application,
f — Utilization equipment does not generally operate directly at these voltages. For equipment supplied
through transformers, refer to limits for nominal system voltage of transformer output,
g — For these systems. Range A and Range B limits are not shown because, where they are used as
service voltages, the operating voltage level on the user’s system is normally adjusted by means of volt-
age regulation to suit their requirements.

h — Standard voltages are reprinted from ANSI C92. 2-1987 for convenience only,
i— Nominal utilization voltages are for low-voltage motors and control. See ANSI C84. 1-1989, Appen-
dix C, for other equipment nominal utilization voltages (or equipment nameplate voltage ratings).

subtransmission and primary distribution. Transmission lines also interconnect trans-
mission substations to provide alternate paths for power transmission for higher
reliability.

3.1.4 Voltage systems outside of the United States

Voltage systems in other countries generally differ from those in the United States. For exam-
ple, 415Y/240 V and 380Y/220 V are widely used as utilization voltages even for residential
service. Also, the frequency in many countries is 50 Hz instead of 60 Hz, which affects the
operation of some equipment such as motors. Motors on 50 Hz systems run approximately
17% slower than in the United States. Plugs and receptacles are generally different, and this
helps to prevent utilization equipment from the United States from being connected to the
wrong voltage.

Users should check with the equipment manufacturer before attempting to operate equipment
on a voltage or frequency for which the equipment is not specifically rated. Equipment rated
for use with one voltage and frequency often cannot be used or may not give adequate
performance on another voltage or frequency. Some equipment has multiple voltage and/or
frequency ratings for application on a variety of systems. If electric equipment made for use
on one system must be used on a different system, information on the voltage, frequency, and
type of plug required should be obtained. If the difference is only in the voltage, transformers
are generally available to convert the available supply voltage to match the equipment
voltage.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

SINGLE-PHASE SYSTEMS

TWO-WIRE

NEUTRAL

i 1

( 2 )

THREE-WIRE

THREE-PHASE THREE-WIRE SYSTEMS (NOTE b)

WYE

(4)

TEE

r ■
. 1 .

(NOTE c)

r ■
. 1 .

(5)

DELTA

(NOTE c)

( 6 )

OPEN-DELTA

THREE-PHASE FOUR-WIRE SYSTEMS

NEUTRAL

( 8 )

TEE

NOTES

a — The above diagrams show connections of transformer secondary windings to supply the nominal sys-
tem voltages of table 3-1. Systems of more than 600 V are normally three phase and supplied by connec-
tions (3), (5) ungrounded, or (7). Systems of 120-600 V may be either single phase or three phase and
all of the connections shown are used to some extent for some systems in this voltage range,
b — Three-phase, three-wire systems may be solidly grounded, impedance grounded, or ungrounded, but
are not intended to supply loads connected phase-to-neutral (as the four-wire systems are),
c — In connections (5) and (6), the ground may be connected to the midpoint of one winding as shown (if
available), to one phase conductor ( corner grounded), or omitted entirely (ungrounded),
d — Single-phase services and single-phase loads may be supplied from single-phase systems or from
three-phase systems. They are connected phase-to-phase when supplied from three-phase, three-wire
systems and either phase-to-phase or phase-to-neutral from three-phase, four-wire systems.

Figure 3-1 —Principal transformer connections
to supply the system voltages of table 3-1

IEEE

Std 141-1993

CHAPTER 3

3.1 .5 Voltage standard for Canada

The voltage standard for Canada is CAN3-C235-83. This standard differs from the United
States standard in both the list of standard nominal voltages and the tolerance limits.

3.2 Voltage control in electric power systems

Power supply systems and utilization equipment should be designed to be compatible. This
requires coordinated efforts and standards that place requirements on voltage ranges supplied
by utilities, allowable voltage drops in plant distribution systems, and voltage ranges for utili-
zation equipment. This section outlines these coordinated efforts and standards associated
with assuring good operation of the utilization equipment.

3.2.1 Principles of power transmission and distribution in utility systems

A general understanding of the principles of power transmission and distribution in utility
systems is necessary since most industrial plants obtain most of their electric power from the
local electric utility. Figure 3-2 shows a simplified one-line diagram of a typical utility power
generation, transmission, and distribution system.

Figure 3-2— Typical utility generation,
transmission and distribution system

Most utility generating stations are located near sources of water, often a considerable dis-
tance from major load areas. Generated power, except for station requirements, is trans-
formed in a transmission substation located at the generating station to voltage generally
69 000 V or higher for transmission to major load areas. These transmission lines are usually
interconnected in large free flowing networks. For example, most transmission lines in the
eastern half of the United States are interconnected to form one network. Utilities are con-
stantly adjusting generation to match the load. They adjust generation to regulate the 60 Hz
frequency, keeping clocks on time within a few seconds. Transmission lines are generally for

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

bulk energy transfers and are controlled only to keep the lines operating within normal volt-
age limits and to facilitate power flow. ANSI C84. 1-1989 and ANSI C92. 2-1987 specify
nominal and maximum but no minimum values for systems over 34 500 V.

Transmission line networks supply distribution substations equipped with transformers that
step the transmission voltage down to a primary distribution voltage generally in the range
from 4160 to 34 500 V with 12 470, 13 200, and 13 800 V in widest use. There is an increas-
ing trend in the electric utility industry to use 23 kV and 34.5 kV for distribution. If the sup-
plying utility offers one of these voltages for primary distribution within a building,
competent electricians experienced in making splices and terminations must be secured to
obtain a good installation.

Voltage control is applied when necessary for the purpose of supplying satisfactory voltage to
the terminals of utilization equipment. Transformers stepping the transmission voltage down
to the primary distribution voltage are generally equipped with automatic tap-changing-
under-load equipment, which changes the turns ratio of the transformer under load. This reg-
ulates the primary distribution voltage within a specific range of values regardless of fluctua-
tions in the transmission voltage or load. Separate step or induction regulators may also be
used.

If the load is remote from the substation, the regulator controls are equipped with compensa-
tors that raise the voltage as the load increases and lower the voltage as the load decreases to
compensate for the voltage drop in the primary distribution system that extends radially from
the substation. This effectively regulates the voltage at a point of the primary distribution sys-
tem some distance from the substation. This is illustrated in figure 3-3. Note that plants close
to the substation will receive voltages which, on the average, will be higher than those
received by plants at a distance from the distribution substation. See 3.2.8 on the use of distri-
bution transformer taps. Switched or fixed capacitors are also used to improve the voltage on
primary feeders.

Figure 3-3— Effect of regulator compensation
on primary distribution system voltage

IEEE

Std 141-1993

CHAPTER 3

The primary distribution system supplies distribution transformers that step the primary dis-
tribution voltage down to utilization voltages generally in the range of 120 to 600 V to supply
a secondary distribution system to which the utilization equipment is connected. Distribution
transformers generally do not have any automatic means for regulating the utilization voltage.
Small transformers used to step a higher utilization voltage down to a lower utilization volt-
age, such as 480 V to 208Y/120 V, are considered part of the secondary distribution system.

The supply voltages available to an industrial plant depend upon whether the plant is con-
nected to the distribution transformer, the primary distribution system, or the transmission
system, which in turn depends on the size of the plant load.

Small plants with loads up to several hundred kilovoltamperes and all plants supplied from
low-voltage secondary networks are connected to the distribution transformer, and the sec-
ondary distribution system consists of the connections from the distribution transformer to
the plant service and the plant wiring.

Medium-sized plants with loads of a few thousand kilovoltamperes are connected to the pri-
mary distribution system, and the plant provides the portion of the primary distribution sys-
tem within the plant, the distribution transformers, and the secondary distribution system.

Large plants with loads of more than a few thousand kilovoltamperes are connected to the
transmission system, and the plant provides the primary distribution system, the distribution
transformers, the secondary distribution system, and it may provide the distribution substation.

Details of the connection between the utility system and the plant system will depend on the
policy of the supplying utility. Refer to Chapter 15 for more detailed information about utility
interface considerations.

3.2.2 System voltage tolerance limits

ANSI C84. 1-1989 specifies the preferred nominal voltages and operating voltage ranges for
utilization and distribution equipment operating from 120-34 500 V in the United States. It
specifies voltages for two critical points on the distribution system: the point of delivery by
the supplying utility and the point of connection to utilization equipment. For transmission
voltages over 34 500 V, ANSI C84. 1-1989 only specifies the nominal and maximum voltage
because these voltages are normally unregulated and only a maximum voltage is required to
establish the design insulation level for the line and associated apparatus.

The actual voltage measured at any point on the system will vary depending on the location
of the point of measurement and the system load at the time the measurement is made. Fixed
voltage changes take place in transformers in accordance with the transformer ratio. Voltage
variations occur from the operation of voltage control equipment, changes in voltage drop
due to changes in load current, and other reasons. It should be recognized that because of
conditions beyond the control of the supplier or user, or both, there will be infrequent and
limited periods when sustained voltages outside range B limits will occur.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

The tolerance limits for the service voltage provide guidance to the supplying utility for the
design and operation of its distribution system. The service voltage is the voltage at the point
where the utility conductors connect to the user conductors. It is generally measured at the
service switch for services of 600 V and below and at the billing meter voltage (potential)
transformers for services over 600 V. The tolerance limits for the voltage at the point of con-
nection of utilization equipment provide guidance to the user for the design and operation of
the user distribution system, and to utilization equipment manufacturers for the design of uti-
lization equipment. Electric supply systems are to be designed and operated so that most ser-
vice voltages fall within the range A limits. User systems are to be designed and operated so
that, when the service voltages are within range A, the utilization voltages are within range A.
Utilization equipment is to be designed and rated to give fully satisfactory performance
within the range A limits for utilization voltages.

Range B allows limited excursions of voltage outside the range A limits that necessarily
result from practical design and operating conditions. When voltages are outside range A and
inside range B, the corrective action should be taken within a reasonable time to restore ser-
vice voltages to range A limits. Insofar as practicable, utilization equipment may be expected
to give acceptable performance at voltages outside range A but within range B. When volt-
ages occur outside the limits of range B, prompt corrective action should be taken. Responsi-
bility for corrective action depends upon where the voltage is out of range A compared to the
limits specified for each location identified in ANSI C84. 1-1989.

3.2.3 Development of the voltage tolerance limits for ANSI C84.1-1989

The voltage tolerance limits in ANSI C84. 1-1989 are based on NEMA MG 1-1993, which
established the voltage tolerance limits of the standard induction motor at ±10% of nameplate
ratings of 230 V and 460 V. Since motors represent the major component of utilization equip-
ment, they were given primary consideration in the establishment of the voltage standard.

The best way to show the voltages in an electric power distribution system is in terms of a
120 V base. This cancels the transformation ratios between systems so that the actual voltages
vary solely on the basis of the voltage drops in the system. Any voltage may be converted to a
120 V base by dividing the actual voltage by the ratio of transformation to the 120 V base.
For example, the ratio of transformation for the 480 V system is 480/120 or 4, so 460 V in a
480 V system would be 460/4 or 1 15 V on a 120 V base.

The tolerance limits of the 460 V motor in terms of the 120 V base become 115 V plus 10%,
or 126.5 V, and 115 V minus 10%, or 103.5 V. The problem is to decide how this tolerance
range of 23 V should be divided between the primary distribution system, the distribution
transformer, and the secondary distribution system, which make up the regulated distribution
system. The solution adopted by ANSI Accredited Committee C84 is shown in table 3-2.

The Range B tolerance limits raised the standard motor tolerance on the 120 V base 0.5 V to
127 V maximum and 104 V minimum to eliminate the fractional volt. These values became
the tolerance limits for range B in the standard. An allowance of 13 V was allotted for the
voltage drop in the primary distribution system. Deducting this voltage drop from 127 V
establishes a minimum of 114 V for utility services supplied from the primary distribution

IEEE

Std 141-1993

CHAPTER 3

Table 3-2— Standard voltage profile for
low-voltage regulated power distribution system, 120 V base

Range A

(V)

Range B

(V)

Maximum allowable voltage

126 (125*)

127

Voltage drop allowance for primary distribution line

Minimum primary service voltage

117

114

Voltage drop allowance for distribution transformer

Minimum secondary service voltage

114

110

Voltage drop allowance for plant wiring

6(4f)

Minimum utilization voltage

108 (llOf)

104 (106f)

*For utilization voltage of 120-600 V.
f For building wiring circuits supplying lighting equipment.

system. An allowance of 4 V was provided for the voltage drop in the distribution transformer
and the connections to the plant wiring. Deducting this voltage drop from the minimum pri-
mary distribution voltage of 114 V provides a minimum of 110 V for utility secondary ser-
vices from 120-600 V. An allowance of 6 V, or 5%, for the voltage drop in the plant wiring, as
provided in ANSI/NFPA 70-1993 (the National Electrical Code [NEC]) Articles 210-19(a)
(FPN No. 4) and 215-2(b) (FPN No. 2), provides the minimum utilization voltage of 104 V.

The range A limits for the standard were established by reducing the maximum tolerance lim-
its from 127 V to 126 V and increasing the minimum tolerance limits from 104 V to 108 V.
The spread band of 18 V was then allotted as follows: 9 V for the voltage drop in the primary
distribution system to provide a minimum primary service voltage of 117 V; 3 V for the volt-
age drop in the distribution transformer and secondary connections to provide a minimum
secondary service voltage of 1 14 V; and 6 V for the voltage drop in the plant low-voltage wir-
ing to provide a minimum utilization voltage of 108 V.

Four additional modifications were made in this basic plan to establish ANSI C84. 1-1989.
The maximum utilization voltage in range A was reduced from 126 V to 125 V for low- volt-
age systems in the range from 120 to 600 V because there should be sufficient load on the dis-
tribution system to provide at least 1 V drop on the 120 V base under most operating
conditions. This maximum voltage of 125 V is also a practical limit for lighting equipment
because the life of the 120 V incandescent lamp is reduced by 42% when operated at 125 V
(see 3.5.4, table 3-9). The voltage drop allowance of 6 V on the 120 V base for the drop in the
plant wiring was reduced to 4 V for circuits supplying lighting equipment. This raised the
minimum voltage limit for utilization equipment to 106 V in range B and 1 10 V in range A

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

because the minimum limits for motors of 104 V in range B and 108 V in range A were con-
sidered too low for satisfactory operation of lighting equipment. The utilization voltages for
the 6900 V and 13 800 V systems in range B were adjusted to coincide with the tolerance lim-
its of ±10% of the nameplate rating of the 6600 V and 13 200 V motors used on these respec-
tive systems.

To convert the 120 V base voltage to equivalent voltages in other systems, the voltage on the
120 V base is multiplied by the ratio of the transformer that would be used to connect the
other system to a 120 V system. In general, distribution transformers for systems below
15 000 V have nameplate ratings that are the same as the standard system nominal voltages;
so the ratio of the standard nominal voltages may be used to make the conversion. However,
for primary distribution voltages over 15 000 V, the primary nameplate rating of distribution
transformers is not the same as the standard system nominal voltages. Also, most distribution
transformers are equipped with taps that can be used to change the ratio of transformation. So
if the primary distribution voltage is over 15 000 V, or taps have been used to change the
transformer ratio, then the actual transformer ratio must be used to convert the base voltage to
another system.

For example, the maximum tolerance limit of 127 V on the 120 V base for the service voltage
in range B is equivalent, on the 4160 V system, to 4160 ± 120 • 127 = 4400 V to the nearest
10 V. However, if the 4160-120 V transformer is set on the +2'h% tap, the voltage ratio would
be 4160 + (4160 ■ 0.025) = 4160 + 104 = 4264 to 120. The voltage on the primary system
equivalent to 127 V on the secondary system would be 4264 ± 120 • 127 = 35.53 • 127 =
4510 V to the nearest 10 V. If the maximum primary distribution voltage of 4400 V is applied
to the 4264-120 V transformer, the secondary voltage would be 4400 -=- 4260 • 120 = 124 V.

3.2.4 Voltage profile limits for a regulated distribution system

Figure 3-4 shows the voltage profile of a regulated power distribution system using the limits
of range A in table 3-1. Assuming a nominal primary distribution voltage of 13 800 V, range
A in table 3-1 shows that this voltage should be maintained by the supplying utility between a
maximum of 126 V and a minimum of 1 17 V on a 120 V base. Since the base multiplier for
converting from the 120 V system to the 13 800 V system is 13 800/120 or 115, the actual
voltage limits for the 13 800 V system are 1 15 ■ 126 or 14 490 V maximum and 115 • 117 or
1 3 460 V minimum.

If a distribution transformer with a ratio of 13 800 to 480 V is connected to the 13 800 V dis-
tribution feeder, range A of table 3-1 requires that the nominal 480 V secondary service be
maintained by the supplying utility between a maximum of 126 V and a minimum of 114 V
on the 120 V base. Since the base multiplier for the 480 V system is 480/120 or 4, the actual
values are 4 • 126 or 504 V maximum and 4 • 1 14 or 456 V minimum.

Range A of table 3-1 as modified for utilization equipment of 120-600 V provides for a max-
imum utilization voltage of 125 V and a minimum of 1 10 V for lighting equipment and 108 V
for other than lighting equipment on the 120 V base. Using the base multiplier of 4 for the
480 V system, the maximum utilization voltage would be 4 • 125 V or 500 V and the mini-
mum for other than lighting equipment would be 4 ■ 108 V or 432 V. For lighting equipment

VOLTAGE ON A 120 V BASE

IEEE

Std 141-1993

CHAPTER 3

125 H

120 -4

1 15 H

110 H

MAXIMUM VOLTAGE LIMIT - RANGE A - 14 490-504 (126)

500 (125)

ALLOWABLE VOLTAGE DROP IN THE
DISTRIBUTION FEEDER

TOLERANCE LIMITS FOR
SERVICES OVER 600 V

ALLOWABLE VOLTAGE DROP IN THE
DISTRIBUTION TRANSFORMER AND
LOW-VOLTAGE CONNECTIONS

ALLOWABLE VOLTAGE DROP
IN THE BUILDING WIRING
FOR LIGHTING EQUIPMENT

TOLERANCE LIMIT
FOR SERVICES
FROM 120
THROUGH 600 V

TOLERANCE
LIMITS FOR
LIGHTING
EQUIPMENT

ALLOWABLE VOLTAGE DROP IN THE BUILDING WIRING FOR OTHER
THAN LIGHTING EQUIPMENT

TOLERANCE
LIMITS FOR
OTHER THAN
LIGHTING
EQUIPMENT

440 (1 10)

NOTE: Limits provided by ANSI C84.1-1989; see table 3-1.

Figure 3-4— Range A voltage profile limits

connected phase to neutral, the maximum voltage would be 500 V divided by the square root
of 3 or 288 V and the minimum voltage would be 4 • 1 10 V or 440 V divided by the square
root of 3 or 254 V.

3.2.5 System voltage nomenclature

The nominal system voltages in table 3- 1 are designated in the same way as on the nameplate
of the transformer for the winding or windings supplying the system.

a) Single-Phase Systems

120 Indicates a single-phase, two-wire system in which the nominal voltage

between the two wires is 120 V.

120/240 Indicates a single-phase, three- wire system in which the nominal voltage
between the two phase conductors is 240 V, and from each phase conduc-
tor to the neutral it is 120 V.

b) Three-Phase Systems

240/120 Indicates a three-phase, four- wire system supplied from a delta connected
transformer. The midtap of one winding is connected to a neutral. The
three-phase conductors provide a nominal 240 V three-phase system, and
the neutral and the two adjacent phase conductors provide a nominal 120/
240 V single-phase system.

480 Indicates a three-phase, three-wire system in which the number desig-

nates the nominal voltage between phases.

480Y/277 Indicates a three-phase, four-wire system from a wye-connected trans-
former in which the first number indicates the nominal phase-to-phase volt-
age and the second number indicates the nominal phase-to-neutral voltage.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

NOTES

1— All single-phase systems and all three-phase, four- wire systems are suitable for the connection of
phase-to-neutral load.

2— See Chapter 7 for methods of system grounding.

3 — Figure 3-5 gives an overview of voltage relationships for 480 V three-phase systems and 120/240 V
single- and three-phase systems.

480 V Three-Phase System

120/240 V Single-Phase and 240 V Three-Phase Systems

Voltage at Point of Voltage at Point of Voltage at Point of Voltage at Point of

Service Entrance Utilization Equipment Service Entrance Utilization Equipment

Range B Range A Voltage Range A Range B Range B Range A Voltage Range A Range B

— 510 —

— 508 — 105.8%^ 1

► 105.0% — 504 —

— 500 — 104.2%

•h

•*91.7%

— 490 —

Syitem — 480 — Tr»n*.
100 % *

— 470— 4.2%

— 460 — Motor

■►95.0% — 456 —

— 450 —

— 440 — 91. 7%^

— 432— 90.0%* 1

— 430 —

— 424 — 88.3 %4*

— 420 —

— 416 —

— 130/260 —

(►105.8% — 127/254 —

>105.0% — 1 26/252 —

— 125/250— 104.2% 4-

System — 120/250 — Tran*.

100% 4

4.2%

— 116/232— ^

— 11 S/230— Motor
► 95.0% — 114/228 —

— 112/224 —

*91.7%

— 110 / 220 — 91.7 % 4 *

— 108/216 — 90.0%4- J 88.3%* 1

■ 2 %

— 105/210 —

— 104/208 —

86.7%*- J

5.7%*-

Lighting or Combination Lighting and Power Circuit*
•— — — Power Circuits

Figure 3-5— Voltage relationships based on
voltage ranges in ANSI C84.1-1989

3.2.6 Nonstandard nominal system voltages

Since ANSI C84.I-1989 lists only the standard nominal system voltages in common use in the
United States, system voltages will frequently be encountered that differ from the standard
list. A few of these may be so widely different as to constitute separate systems in too limited
use to be considered standard. However, in most cases the nominal system voltages will differ
by only a few percent as shown in table 3-3. A closer examination of the table shows that
these differences are due mainly to the fact that some voltages are multiples of 1 10 V, others
are multiples of 1 15 V, some are multiples of 120 V, and a few are multiples of 125 V.

The reasons for these differences go back to the original development of electric power distri-
bution systems. The first utilization voltage was 100 V. However, the supply voltage had to be
raised to 1 10 V in order to compensate for the voltage drop in the distribution system. This
led to overvoltage on equipment connected close to the supply, so the utilization equipment

IEEE

Std 141-1993

CHAPTER 3

Table 3-3— Nominal system voltages

Standard nominal system voltages

Associated nonstandard
nominal system voltages

Low voltages

120

110, 115, 125

120/240

110/220, 115/230. 125/250

208Y/120

216Y/125

240/120

240

230, 250

480Y/277

460Y/265

480

440

600

550, 575

Medium voltages

2400

2200, 2300

4160Y/2400

4160

4000

4800

4600

6900

6600, 7200

8320Y/4800

11 000, 11 500

12 000Y/6930

12 470Y/7200

13 200Y/7620

13 200

13 800Y/7970

14 400

13 800

20 780Y/12 000

22 860Y/13 200

23 000

24 940Y/14 400

34 500Y/19 920

34 500

33 000

46 000

44 000

69 000

66 000

High voltages

1 15 000

110 000, 120 000

138 000

132 000

161 000

154 000

230 000

220 000

Extra-high voltages

345 000

500 000

765 000

rating was also raised to 1 10 V. As generator sizes increased and distribution and transmission
systems developed, an effort to keep transformer ratios in round numbers led to a series of
utilization voltages of 110, 220, 440, and 550 V, a series of primary distribution voltages of
2200, 4400, 6600, and 13 200 V, and a series of transmission voltages of 22 000, 33 000,
44 000, 66 000, 1 10 000, 132 000, and 220 000 V.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

As a result of the effort to maintain the supply voltage slightly above the utilization voltage,
the supply voltages were raised again to multiples of 1 15 V, which resulted in a new series of
utilization voltages of 1 15, 230, 460, and 575 V, a new series of primary distribution voltages
of 2300, 4600, 6900, and 13 800 V, and a new series of transmission voltages of 23 000,
34 500, 46 000, 69 000, 1 15 000, 138 000, and 230 000 V.

As a result of continued problems with the operation of voltage-sensitive lighting equipment
and voltage-insensitive motors on the same system, and the development of the 208Y/120 V
network system, the supply voltages were raised again to multiples of 120 V. This resulted in
a new series of utilization voltages of 120, 208Y/120, 240, 480, and 600 V, and a new series
of primary distribution voltages of 2400, 4160Y/2400, 4800, 12 000, and 12 470Y/7200 V.
However, most of the existing primary distribution voltages continued in use and no 120 V
multiple voltages developed at the transmission level.

3.2.7 Standard nominal system voltages in the United States

The nominal system voltages listed in the left-hand column of table 3-3 are designated as
standard nominal system voltages in the United States by ANSI C84. 1-1989. In addition,
those shown in boldface type in table 3- 1 are designated as preferred standards to provide a
long-range plan for reducing the multiplicity of voltages.

In the case of utilization voltages of 600 V and below, the associated nominal system voltages
in the right-hand column are obsolete and should not be used. Where possible, manufacturers
are encouraged to design utilization equipment to provide acceptable performance within the
utilization voltage tolerance limits specified in the standard. Some numbers listed in the right-
hand column are used in equipment ratings, but these should not be confused with the num-
bers designating the nominal system voltage on which the equipment is designed to operate.

In the case of primary distribution voltages, the numbers in the right-hand column may desig-
nate an older system in which the voltage tolerance limits are maintained at a different level
than the standard nominal system voltage, and special consideration should be given to the
distribution transformer ratios, taps, and tap settings.

3.2.8 Use of distribution transformer taps to shift utilization voltage spread
band

Power and distribution transformers often have four taps on the primary winding in 2'h%
steps. These taps are generally +5%, +2'/2%, nominal, and -5%. These taps allow

users to change the transformer ratio and raise or lower the secondary voltage to provide a
closer fit to the tolerance limits of the utilization equipment. There are three situations requir-
ing the use of taps:

a) Taps are required when the primary voltage has a nominal value that is slightly differ-
ent from the transformer primary nameplate rating. For example, if a 13 20CM-80 V
transformer is connected to a nominal 13 800 V system, the nominal secondary volt-
age would be (13 800/13 200) • 480 = 502 V. However, if the 13 800 V system were
connected to the +5% tap of the 13 200-480 V transformer at 13 860 V, the nominal

IEEE

Std 141-1993

CHAPTER 3

secondary voltage would be (13 800/13 860) • 480 = 478, which is practically the
same as would be obtained from a transformer having the proper ratio of 13 800-
480 V.

b) Taps are required when the primary voltage spread is in the upper or lower portion of
the tolerance limits provided in ANSI C84. 1-1989. For example, a 13 200-480 V
transformer is connected to a 1 3 200 V primary distribution system close to the sub-
station where the primary voltage spread band stays in the upper half of the tolerance
zone for range A, or 13 200-13 860 V. This would result in a nominal secondary
voltage under no-load conditions of 480 to 504 V. By setting the transformer on the
+2 l h% tap at 13 530 V, the no-load secondary voltage would be lowered 2 l /i% to a
range of 468-491 V.

c) Taps are required to adjust the utilization voltage spread band to provide a closer fit to
the tolerance limits of the utilization equipment. For example, table 3-4 shows the
shift in the utilization voltage spread band for the +2 l h% and 5% taps as compared to
the utilization voltage tolerance limits for range A of ANSI C84. 1-1989 for the 480 V
system. Table 3-5 shows the voltage tolerance limits of standard 460 V and 440 V
three-phase induction motors. Table 3-6 shows the tolerance limits for standard
277 V and 265 V fluorescent lamp ballasts. A study of these three tables shows that a
tap setting of nominal will provide the best fit with the tolerance limits of the 460 V
motor and the 277 V ballast, but a setting on the +5% tap will provide the best fit for
the 440 V motor and the 265 V ballast. For buildings having appreciable numbers of
both ratings of motors and ballasts, a setting on the +2 l h% tap may provide the best
compromise.

Table 3-4— Tolerance limits for lighting circuits from table 3-1, range A, in volts

Nominal system
voltage (volts)

Transformer tap

Minimum utilization
voltage (volts)

Maximum
utilization voltage
(volts)

480Y/277

Nominal

440Y/254

500Y/288

468Y/270

+ 2 x h%

429Y/248

488Y/281

456Y/263

+ 5%

418Y/241

475Y/274

Table 3-5— Tolerance limits for low-voltage three-phase motors, in volts

Motor rating (volts)

-10%

+10%

460

414

506

440

396

484

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

Table 3-6— Tolerance limits for low-voltage standard
fluorescent lamp ballasts, in volts

Ballast rating (volts)

Minimum

-10%

Maximum

+10%

277

254

289

120

110

125

Note that these examples assume that the tolerance limits of the supply and utilization volt-
ages are within the tolerance limits specified in ANSI C84. 1-1989. This may not be true, so
the actual voltages should be recorded over a time period that provides voltage readings dur-
ing the night and over weekends when maximum voltages often occur. These actual voltages
can then be used to calculate voltage profiles similar to figure 3-4 to check the proposed
transformer ratios and tap settings. If transformer taps are used to compensate for voltage
drop, the voltage profile should be calculated for light-load periods to check for possible
overvoltage situations.

Where a plant has not yet been built, the supplying utility should be requested to provide the
expected spread band for the supply voltage, preferably supported by a seven-day graphic
chart from the nearest available location. If the plant furnishes the distribution transformers,
recommendations should also be obtained from the supplying utility on the transformer
ratios, taps, and tap settings. With this information, a voltage profile can be prepared to check
the expected voltage spread at the utilization equipment.

Where the supplying utility offers a voltage over 600 V that differs from the standard nominal
voltages listed in ANSI C84.1-1989, the supplying utility should be asked to furnish the
expected tolerance limits of the supply voltage, preferably supported by seven or more days
of voltage recordings from a nearby location. The supplying utility should also be asked for
the recommended distribution transformer ratio and tap settings to obtain a satisfactory utili-
zation voltage range. With this information, a voltage profile for the supply voltage and utili-
zation voltage limits can be constructed for comparison with the tolerance limits of utilization
equipment. If the supply voltage offered by the utility is one of the associated nominal system
voltages listed in table 1-1, the taps on a standard distribution transformer will generally be
sufficient to adjust the distribution transformer ratio to provide a satisfactory utilization volt-
age range.

Taps are on the primary side of transformers. Therefore, raising the tap setting to +2 l h%
increases the transformer ratio by 2 l h% and lowers the secondary voltage spread band by
272% minus the voltage drop in the transformer. Taps only serve to move the secondary volt-
age spread band up or down in the steps of the taps. They cannot correct for excessive spread
from the supply voltage or from excessive drop in the plant wiring system. If the voltage
spread band at the utilization equipment falls outside the satisfactory operating range of the
equipment, then action must be taken to improve voltage conditions by other means (see 3.7).

IEEE

Std 141-1993

CHAPTER 3

In general, transformers should be selected with the same primary nameplate voltage rating
as the nominal voltage of the primary supply system, and the same secondary voltage rating
as the nominal voltage of the secondary system. Taps should be provided at +2'h% and +5%
and at -2 l h% and -5% to allow for adjustment in either direction.

3.3 Voltage selection

3.3.1 Selection of low-voltage utilization voltages

The preferred utilization voltage for industrial plants is 480Y/277 V. Three-phase power and
other 480 V loads are connected directly to the system at 480 V, and gaseous discharge light-
ing is connected phase-to-neutral at 277 V. Small dry-type transformers rated 480-208 Y/
120 V are used to provide 120 V, single-phase, for convenience outlets, and 208 V, single-
phase and three-phase, for small tools and other machinery. Where requirements are limited
to 120 or 240 V, single-phase, 480-120/240 V single-phase transformers may be used. How-
ever, single-phase transformers should be connected in sequence to the individual phases in
order to keep the load on each phase balanced (see 3.8).

For small industrial plants supplied at utilization voltage by a single distribution transformer,
the choice of voltages is limited to those the utility will supply. However, most utilities will
supply most of the standard nominal voltages listed in ANSI C84. 1-1989 with the exception
of 600 V, although all voltages supplied may not be available at every location. The built-up
downtown areas of most large cities are supplied from secondary networks. Originally only
208Y/120 V was available, but most utilities now provide spot networks at 480Y/277 V for
large installations.

3.3.2 Utility service supplied from a medium-voltage primary distribution line

Industrial plants too large for utilization voltage supply from one distribution transformer,
normally furnished by the utility and located outdoors, generally require a tap from the pri-
mary distribution line. The plant constructs a primary distribution system from this tap to
supply distribution transformers, which are generally dry-type with solid cast or resin-encap-
sulated windings, less flammable liquid, or nonflammable fluid suitable for indoor installa-
tion. Generally these distribution transformers are combined with primary and secondary
switching and protective equipment to become unit substations. They are designated as pri-
mary unit substations when the secondary voltage is over 1000 V and secondary unit substa-
tions when the secondary voltage is 1000 V and below. Primary distribution may also be used
to supply large industrial plants or plants involving more than one building. In this case, the
primary distribution line may be run overhead or underground and may supply distribution
transformers located outside the building or unit substations inside the building.

Original primary distribution voltages were limited to the range from 2400 to 14 400 V, but
the increase in load densities in recent years has forced many utilities to limit expansion of
primary distribution voltages below 15 000 V and to begin converting transmission voltages
in the range from 15 000 to 50 000 V (sometimes called subtransmission voltages) to primary

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

distribution. ANSI C84. 1-1989 provides tolerance limits for primary supply voltages up
through 34 500 V. IEEE Std C57. 12.20-1988 lists overhead distribution transformers for pri-
mary voltages up through 69 000 V.

In case an industrial plant, supplied at utilization voltage from a single primary distribution
transformer, contemplates an expansion that cannot be supplied from the existing trans-
former, a changeover to primary distribution will be required, unless a separate supply to the
new addition is permitted by the local electrical code enforcing authority and the higher cost
resulting from separate bills from the utility is acceptable. In any case, the proposed expan-
sion needs to be discussed with the supplying utility to determine whether the expansion can
be supplied from the existing primary distribution system or whether the entire load can be
transferred to another system. Any utility charges and the plant costs associated with the
changes need to be clearly established.

In general, primary distribution voltages between 15 000 and 25 000 V can be brought into a
plant and handled like the lower voltages. Primary distribution voltages from 25 GOO-
35 000 V will require at least a preliminary economic study to determine whether they can be
brought into the plant or transformed to a lower primary distribution voltage. Voltages above
35 000 V will require transformation to a lower voltage.

In most cases, plants with loads of less than 10 000 kVA will find that 4160 V is the most eco-
nomical plant primary distribution voltage, and plants with loads over 20 000 kVA will find
13 800 V the most economical considering only the cost of the plant wiring and transformers.
If the utility supplies a voltage in the range from 12 000-15 000 V, a transformation down to
4160 V at plant expense cannot normally be justified. For loads of 10 000-20 000 kVA, an
economic study including consideration of the costs of future expansion needs to be made to
determine the most economical primary distribution voltage.

Where overhead lines are permissible on plant property, an overhead primary distribution
system may be built around the outside of the building or to separate buildings to supply util-
ity-type outdoor equipment and transformers. This system is especially economical at volt-
ages over 15 000 V.

Care must be taken to be sure the transformer types and installation methods are compatible
with National Electrical Code (NEC) (ANSI/NFPA 70-1993) requirements, fire insurance
rules, and environmental considerations. A number of transformer types are available up to
40 000 V. Appropriate installation methods can be made to satisfy insurers and code-enforc-
ing authorities.

Utility primary distribution systems are almost always solidly grounded wye systems, and the
neutral is often carried throughout. This grounding method and other factors must be adapted
to the plant distribution system if the utility distribution voltage supplies the plant without
transformers and without grounding methods specifically dedicated to that plant.

IEEE

Std 141-1993

CHAPTER 3

3.3.3 Utility service supplied from medium-voltage or high-voltage
transmission lines

Voltages on transmission lines used to supply large industrial plants range from 23 000 to
230 000 V. There is an overlap with primary distribution system voltages in the range from
23 000 to 69 000 V, with voltages of 34 500 V and below tending to fall into the category of
regulated primary distribution voltages and voltages above 34 500 V tending to fall into the
category of unregulated transmission lines. The transmission voltage will be limited to those
voltages the utility has available in the area. A substation is required to step the transmission
voltage down to a primary distribution voltage to supply the distribution transformers in the
plant.

3.3.3. 1 Substation is supplied by the industrial plant

Most utilities have a low rate for service from unregulated transmission lines which requires
the plant to provide the substation. This permits the plant designer to select the primary distri-
bution voltage but requires the plant personnel to assume the operation and maintenance of
the substation. The substation designer should obtain from the supplying utility the voltage
spread on the transmission line, and recommendations on the substation transformer ratio, tap
provisions, and tap setting, and whether regulation should be provided.

With this information, a voltage profile similar to figure 3-4 is obtained using the actual val-
ues for the spread band of the transmission line and the estimated maximum values for the
voltage drops in the substation transformer, primary distribution system, distribution trans-
formers, and secondary distribution system to obtain the voltage spread at the utilization
equipment. If this voltage spread is not within satisfactory limits, then regulators are required
in the substation, preferably by equipping the substation transformer or transformers with tap
changing under load.

For plants supplied at 13 800 V, the distribution transformers or secondary unit substations
should have a ratio of 13 800-480Y/277 V with two ±2 x h% taps. Where medium-sized
motors in the 200 hp or larger range are used, a distribution transformer stepping down to
4160 V or 2400 V may be more economical than supplying these motors from the 480 V
system.

For plants supplied at 4160 V, the distribution transformers or secondary unit substations
should have a ratio of 4160-480Y/277 V with two ±2 l h% taps. Medium-sized motors of a
few hundred horsepower may economically be connected directly to the 4160 V system, pref-
erably from a separate primary distribution circuit.

3.3.3.2 Distribution substation is supplied by the utility

Most utilities have a rate for power purchased at the primary distribution voltage that is
higher than the rate for service at transmission voltage because the utility provides the substa-
tion. The choice of the primary distribution voltage is limited to those supplied by the partic-
ular utility, but the utility will be responsible for keeping the limits specified for service
voltages in ANSI C84. 1-1989. The utility should be requested to provide recommendations

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

for the ratio of the distribution transformers or secondary unit substations, provisions for taps,
and the tap settings. With this information, a voltage profile similar to figure 3-4 can be con-
structed using the estimated maximum values for the voltage drops in the primary distribution
system, the transformers, and the secondary distribution system to make sure that the utiliza-
tion voltages fall within satisfactory limits.

3.4 Voltage ratings for low-voltage utilization equipment

Utilization equipment is defined as electric equipment that uses electric power by converting
it into some other form of energy such as light, heat, or mechanical motion. Every item of uti-
lization equipment is required to have, among other things, a nameplate listing the nominal
supply voltage for which the equipment is designed. With one major exception, most utiliza-
tion equipment carries a nameplate rating that is the same as the voltage system on which it is
to be used; that is, equipment to be used on 120 V systems is rated 120 V (except for a few
small appliances rated 117 or 118 V), for 208 V systems, 208 V, and so on. The major excep-
tion is motors and equipment containing motors. These are also about the only utilization
equipment used on systems over 600 V. Single-phase motors for use on 120 V systems have
been rated 115 V for many years. Single-phase motors for use on 208 V single-phase systems
are rated 200 V and for use on 240 V single-phase systems are rated 230 V.

Prior to the late 1960s, low-voltage three-phase motors were rated 220 V for use on both 208
and 240 V systems, 440 V for use on 480 V systems, and 550 V for use on 600 V systems.
The reason was that most three-phase motors were used in large industrial plants where rela-
tively long circuits resulted in voltages considerably below nominal at the ends of the circuits.
Also, utility supply systems had limited capacity and low voltages were common during
heavy-load periods. As a result, the average voltage applied to three-phase motors approxi-
mated the 220, 440, and 550 V nameplate ratings.

In recent years, supplying electric utilities have made extensive changes to higher distribution
voltages. Increased load density has resulted in shorter primary distribution systems. Distri-
bution transformers have been moved inside buildings to be closer to the load. Lower imped-
ance wiring systems have been used in the secondary distribution system. Capacitors have
been used to improve power factors. All of these changes have contributed to reducing the
voltage drop in the distribution system which raised the voltage applied to utilization equip-
ment. By the mid-1960s, surveys indicated that the average voltage supplied to 440 V motors
on 480 V systems was 460 V, and there were increasing numbers of complaints of overvolt-
ages as high as 500 V during light-load periods.

At about the same time, the Motor and Generator Committee of the National Electrical Man-
ufacturers Association (NEMA) decided that the improvements in motor design and insula-
tion systems would allow a reduction of two frame sizes for standard induction motors rated
600 V and below. However, the motor voltage tolerance would be limited to ±10% of the
nameplate rating. As a result, the nameplate voltage rating of the new motor designated as the
T-frame motor was raised from the 220/440 V rating of the U-frame motor to 230/460 V. Sub-
sequently, a motor rated 200 V for use on 208 V systems was added to the program. Table 3-7
shows the nameplate voltage ratings of standard induction motors, as specified in NEMA
MG 1-1978.

IEEE

Std 141-1993

CHAPTER 3

Table 3-7— Nameplate voltage ratings of standard induction motors

Nominal system voltage

Nameplate voltage

Single-phase motors

120

115

240

230

Three-phase motors

208

200

240

230

480

460

600

575

2400

2300

4160

4000

4800

4600

6900

6600

13 800

13 200

The question has been raised why the confusion between equipment ratings and system nom-
inal voltage cannot be eliminated by making the nameplate rating of utilization equipment the
same as the nominal voltage of the system on which the equipment is to be used. However,
manufacturers say that the performance guarantee for utilization equipment is based on the
nameplate rating and not the system nominal voltage. For utilization equipment such as
motors where the performance peaks in the middle of the tolerance range of the equipment,
better performance can be obtained over the tolerance range specified in ANSI C84. 1-1989
by selecting a nameplate rating closer to the middle of this tolerance range.

3.5 Effect of voltage variations on low-voltage and
medium-voltage utilization equipment

3.5.1 General effects

When the voltage at the terminals of utilization equipment deviates from the value on the
nameplate of the equipment, the performance and the operating life of the equipment are
affected. The effect may be minor or serious depending on the characteristics of the equip-
ment and the amount of the voltage deviation from the nameplate rating. Generally, perform-
ance conforms to the utilization voltage limits specified in ANSI C84. 1-1989, but it may vary
for specific items of voltage-sensitive equipment. In addition, closer voltage control may be
required for precise operations.

3.5.2 Induction motors

The variation in characteristics as a function of the applied voltage is given in table 3-8.
Motor voltages below nameplate rating result in reduced starting torque and increased full-
load temperature rise. Motor voltages above nameplate rating result in increased torque.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

increased starting current, and decreased power factor. The increased starting torque will
increase the accelerating forces on couplings and driven equipment. Increased starting cur-
rent causes greater voltage drop in the supply circuit and increases the voltage dip on lamps
and other equipment. In general, voltages slightly above nameplate rating have less detrimen-
tal effect on motor performance than voltages slightly below nameplate rating.

Table 3-8— General effect of voltage variations
on induction-motor characteristics

Characteristic

Proportional to

Voltage variation

90% of nameplate

110% of nameplate

Starting and maximum
running torque

Voltage squared

-19%

+21%

Percent slip

(1/voltage) 2

+23%

-19%

Full load speed

Synchronous
speed — slip

-0.2 to -1.0%

+0.2 to 1.0%

Starting current

Voltage

-10%

+ 10%

Full load current

Varies with design

+5 to +10%

-5 to -10%

No load current

Varies with design

-10 to -30%

+ 10 to +30%

Temperature rise

Varies with design

+ 10 to +15%

-10 to -15%

Full load efficiency

Varies with design

-1 to -3%

+1 to +3%

Full load power factor

Varies with design

+3 to +7%

-2 to -7%

Magnetic noise

Varies with design

Slight decrease

Slight increase

3.5.3 Synchronous motors

Synchronous motors are affected in the same manner as induction motors, except that the
speed remains constant (unless the frequency changes) and the maximum or pull-out torque
varies directly with the voltage if the field voltage remains constant, as in the case where the
field is supplied by a generator on the same shaft with the motor. If the field voltage varies
with the line voltage as in the case of a static rectifier source, then the maximum or pull-out
torque varies as the square of the voltage.

IEEE

Std 141-1993

CHAPTER 3

3.5.4 Incandescent lamps

The light output and life of incandescent filament lamps are critically affected by the
impressed voltage. The variation of life and light output with voltage is given in table 3-9.
The figures for 125 V and 130 V lamps are also included because these ratings are useful in
signs and other locations where long life is more important than light output.

Table 3-9— Effect of voltage variations on incandescent lamps

Applied

voltage

(volts)

Lamp Rating

120 V

125 V

130 V

% life

% light

% life

% light

% life

% light

105

575

880

—

110

310

525

880

115

175

295

500

120

100

170

280

125

118

100

165

130

132

113

100

3.5.5 Fluorescent lamps

Light output for magnetic ballasts varies approximately in direct proportion to the applied
voltage. Thus a 1% increase in applied voltage will increase the light output by 1% and, con-
versely, a decrease of 1% in the applied voltage will reduce the light output by 1%. Light out-
put for electronic ballasts may be more or less dependent on input voltage. Consult with the
manufacturer for the information specific to a particular ballast. The life of fluorescent lamps
is affected less by voltage variation than that of incandescent lamps.

The voltage-sensitive component of the fluorescent fixture is the ballast. It is a small reactor,
transformer, electronic circuit, or combination that supplies the starting and operating volt-
ages to the lamp and limits the lamp current to design values. These ballasts may overheat
when subjected to above-normal voltage and operating temperature, and ballasts with integral
thermal protection may be required. See NEC, Article 410.

3.5.6 High-intensity discharge (HID) lamps (mercury, sodium, and metal halide)

Mercury lamps using a typical reactor ballast will have a 12% change in light output for a 5%
change in terminal voltage. HID lamps may extinguish when the terminal voltage drops

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

below 75% of rated voltage. A constant wattage autotransformer ballast will produce a ±5%
change in lamp wattage for mercury or a ±10% change in wattage for metal halide, when the
line voltage varies ±10%.

Approximate warm-up and restrike times for HID lamps are as follows:

Light source
Mercury vapor
Metal halide
High-pressure sodium
Low-pressure sodium

Warm-up
5 to 7 min

2 to 5 min

3 to 4 min
7 to 10 min

Re-strike
3 to 6 min
10 to 20 min
0.5 to 1 min
1.2 s to 5 min

The lamp life is related inversely to the number of starts so that, if low-voltage conditions
require repeated starting, lamp life will be reduced. Excessively high voltage raises the arc
temperature, which could damage the glass enclosure if the temperature approaches the glass
softening point. See the manufacturers’ catalogs for detailed information.

3.5.7 Infrared heating processes

Although the filaments in the lamps used in these installations are of the resistance type, the
energy output does not vary with the square of the voltage because the resistance varies at the
same time. The energy output varies slightly less than the square of the voltage. Voltage vari-
ations can produce unwanted changes in the process heat available unless thermostatic con-
trol or other regulating means is used.

3.5.8 Resistance heating devices

The energy input and, therefore, the heat output of resistance heaters varies approximately as
the square of the impressed voltage. Thus a 10% drop in voltage will cause a drop of approx-
imately 19% in heat output. This, however, holds true only for an operating range over which
the resistance remains essentially constant.

3.5.9 Electron tubes

Electron tubes are rarely specified in new equipment except for special applications. The cur-
rent-carrying ability or emission of all electron tubes is affected seriously by voltage devia-
tion from nameplate rating. The cathode life curve indicates that the life is reduced by half for
each 5% increase in cathode voltage. This is due to the reduced life of the heater element and
to the higher rate of evaporation of the active material from the surface of the cathode. It is
extremely important that the cathode voltage be kept near rating on electron tubes for satis-
factory service. In many cases this will necessitate a regulated power source. This may be
located at or within the equipment, and often consists of a regulating transformer having con-
stant output voltage or current.

IEEE

Std 141-1993

CHAPTER 3

3.5.10 Capacitors

The reactive power output of capacitors varies with the square of the impressed voltage. A
drop of 10% in the supply voltage, therefore, reduces the reactive power output by 19%, and
where the user has made a sizable investment in capacitors for power factor improvement, the
user loses the benefit of almost 20% of this investment.

3.5.11 Solenoid-operated devices

The pull of ac solenoids varies approximately as the square of the voltage. In general, sole-
noids are designed to operate satisfactorily on 10% overvoltage and 15% undervoltage.

3.5.12 Solid-state equipment

Thyristors, transistors, and other solid-state devices have no thermionic heaters. Thus they are
not nearly as sensitive to long-time voltage variations as the electron tube components they
are largely replacing. Internal voltage regulators are frequently provided for sensitive equip-
ment such that it is independent of supply system regulation. This equipment as well as
power solid-state equipment is, however, generally limited regarding peak reverse voltage,
since it can be adversely affected by abnormal voltages of even microsecond duration. An
individual study of the maximum voltage of the equipment, including surge characteristics, is
necessary to determine the effect of maximum system voltage or whether abnormally low
voltage will result in malfunction.

3.6 Voltage drop considerations in locating the low-voltage
secondary distribution system power source

One of the major factors in the design of the secondary distribution system is the location of
the power source as close as possible to the center of the load. This applies in every case,
from a service drop from a distribution transformer on the street to a distribution transformer
located outside the building or a secondary unit substation located inside the building. Fre-
quently building esthetics or available space require the secondary distribution system power
supply to be installed in a comer of a building without regard to what this adds to the cost of
the building wiring to keep the voltage drop within satisfactory limits.

Figure 3-6 shows that if a power supply is located in the center of a horizontal floor area at
point 0, the area that can be supplied from circuits mn radially from point 0 with specified
circuit constants, and voltage drop would be the area enclosed by the circle of radius 0-X.
However, conduit systems are run in rectangular coordinates so, with this restriction, the area
that can be supplied is reduced to the square X-Y-X'-Y' when the conduit system is run paral-
lel to the axes X-X' and Y-Y'. But the limits of the square are not parallel to the conduit sys-
tem. Thus, to fit the conduit system into a square building with walls parallel to the conduit
system, the area must be reduced to F-H-B-D.

If the supply point is moved to the center of one side of the building, which is a frequent situ-
ation when the transformer is placed outside the building, the area that can be served with the

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

Source: [Bill

Figure 3-6— Effect of secondary distribution system power source location
on area that can be supplied under specified voltage drop limits

specified voltage drop and specified circuit constants is E-A-B-D. If the supply station is
moved to a corner of the building— a frequent location for buildings supplied from the rear or
from the street— the area is reduced to O-A-B-C.

Every effort should be made to place the secondary distribution system supply point as close
as possible to the center of the load area. Note that this study is based on a horizontal wiring
system and any vertical components must be deducted to establish the limits of the horizontal
area that can be supplied.

Using an average value of 30 ft/V drop for a fully loaded conductor, which is a good average
figure for the conductor sizes normally used for feeders, the distances in figure 3-6 for 5%
and VI 2 % voltage drops are shown in table 3-10. For a distributed load, the distances will be
approximately twice the values shown.

3.7 Improvement of voltage conditions

Poor equipment performance, overheating, nuisance tripping of overcurrent protective
devices, and excessive burnouts are signs of unsatisfactory voltage. Abnormally low voltage
occurs at the end of long circuits. Abnormally high voltage occurs at the beginning of circuits
close to the source of supply, especially under lightly loaded conditions such as at night and
over weekends.

IEEE

Std 141-1993

CHAPTER 3

Table 3-10— Areas that can be supplied for specific voltage drops and
voltages at various secondary distribution system power source locations

Nominal system
voltage (volts)

Distance (feet)

5% voltage drop

2Vz% voltage drop

0-X

0-A

0-X

0-A

120/240

360

180

208

312

156

240

360

180

480

720

360

180

In cases of abnormally low voltage, the first step is to make a load survey to measure the
current taken by the affected equipment, the current in the circuit supplying the equipment,
and the current being supplied by the supply source under peak-load conditions to make sure
that the abnormally low voltage is not due to overloaded equipment. If the abnormally low
voltage is due to overload, then corrective action is required to relieve the overloaded
equipment.

If overload is ruled out or if the utilization voltage is excessively high, a voltage survey
should be made, preferably by using graphic voltmeters, to determine the voltage spread at
the utilization equipment under all load conditions and the voltage spread at the utility supply.
This survey can be compared with ANSI C84.1-1989 to determine if the unsatisfactory volt-
age is caused by the plant distribution system or the utility supply. If the utility supply
exceeds the tolerance limits specified in ANSI C84. 1-1989, the utility should be notified. If
the industrial plant is supplied at a transmission voltage and furnishes the distribution substa-
tion. the operation of the voltage regulators should be checked.

If excessively low voltage is caused by excessive voltage drop in the plant wiring (over 5%),
then plant wiring changes are required to reduce the voltage drop. If the load power factor is
low, capacitors may be installed to improve the power factor and reduce the voltage drop.
Where the excessively low voltage affects a large area, the best solution may be conversion to
primary distribution if the building is supplied from a single distribution transformer, or to
install an additional distribution transformer in the center of the affected area if the plant has
primary distribution. Plants wired at 208Y/120 or 240 V may be changed over economically
to 480Y/277 V if an appreciable portion of the wiring system is rated 600 V and motors are
dual rated 220 : 440 V or 230 : 460 V.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

3.8 Phase-voltage unbalance in three-phase systems

3.8.1 Causes of phase-voltage unbalance

Most utilities use four-wire grounded-wye primary distribution systems so that single-phase
distribution transformers can be connected phase-to-neutral to supply single-phase loads,
such as residences and street lights. Variations in single-phase loading cause the currents in
the three-phase conductors to be different, producing different voltage drops and causing the
phase voltages to become unbalanced. Normally the maximum phase-voltage unbalance will
occur at the end of the primary distribution system, but the actual amount will depend on how
well the single-phase loads are balanced between the phases on the system.

Perfect balance can never be maintained because the loads are continually changing, causing
the phase- voltage unbalance to vary continually. Blown fuses on three-phase capacitor banks
will also unbalance the load and cause phase-voltage unbalance.

Industrial plants make extensive use of 480Y/277 V utilization voltage to supply lighting
loads connected phase-to-neutral. Proper balancing of single-phase loads among the three
phases on both branch circuits and feeders is necessary to keep the load unbalance and the
corresponding phase- voltage unbalance within reasonable limits.

3.8.2 Measurement of phase-voltage unbalance

The simplest method of expressing the phase-voltage unbalance is to measure the voltages in
each of the three phases:

The amount of voltage unbalance is better expressed in symmetrical components as the nega-
tive sequence component of the voltage:

. , maximum deviation from average , __

percent unbalance = — • 100

average

t negative-sequence voltage

voltage unbalance factor = — —

positive-sequence voltage

3.8.3 Effect of phase-voltage unbalance

When unbalanced phase voltages are applied to three-phase motors, the phase-voltage unbal-
ance causes additional negative- sequence currents to circulate in the motor, increasing the
heat losses primarily in the rotor. The most severe condition occurs when one phase is opened
and the motor runs on single-phase power. Figure 3-7 shows the recommended derating for
motors as a function of percent phase-voltage unbalance. Linders, 1971 [B7], provides a
more comprehensive review of the effects of unbalance on motors.

2 The numbers in brackets preceded by the letter B correspond to those of the bibliography in 3.13.

IEEE

Std 141-1993

CHAPTER 3

PERCENT VOLTAGE UNBALANCE

Source: NEMA MG 1-1993.

Figure 3-7— Derating factor for motors operating with
phase voltage unbalance

Although there will generally be an increase in the motor load current when the phase volt-
ages are unbalanced, the increase is insufficient to indicate the actual temperature rise that
occurs because NEMA current-responsive thermal or magnetic overload devices only provide
a trip characteristic that correlates with the motor thermal damage due to normal overload
current (positive-sequence) and not negative-sequence current.

All motors are sensitive to phase-voltage unbalance, but hermetic compressor motors used in
air conditioners are most susceptible to this condition. These motors operate with higher cur-
rent densities in the windings because of the added cooling effect of the refrigerant. Thus the
same percent increase in the heat loss due to circulating currents, caused by phase-voltage
unbalance, will have a greater effect on the hermetic compressor motor than it will on a stan-
dard air-cooled motor.

Since the windings in hermetic compressor motors are inaccessible, they are normally
protected by thermally operated switches embedded in the windings, set to open and dis-
connect the motor when the winding temperature exceeds the set value. The motor cannot be
restarted until the winding has cooled down to the point at which the thermal switch will
reclose.

When a motor trips out, the first step in determining the cause is to check the running current
after it has been restarted to make sure that the motor is not overloaded. The next step is to
measure the three-phase voltages to determine the amount of phase-voltage unbalance. Fig-
ure 3-7 indicates that where the phase-voltage unbalance exceeds 2%, the motor is likely to
become overheated if it is operating close to full load.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

Some electronic equipment, such as computers, may also be affected by phase-voltage
unbalance of more than 2 or 2 x h%. The equipment manufacturer can supply the necessary
information.

In general, single-phase loads should not be connected to three-phase circuits supplying
equipment sensitive to phase-voltage unbalance. A separate circuit should be used to supply
this equipment.

3.9 Voltage sags and flicker

The previous discussion has covered the relatively slow changes in voltage associated with
steady-state voltage spreads and tolerance limits. However, sudden voltage changes should be
given special consideration.

Lighting equipment output is sensitive to applied voltage, and people are sensitive to sudden
illumination changes. A voltage change of 0.25 to 0.5% will cause a noticeable reduction in
the light output of an incandescent lamp and a less noticeable reduction in the light output of
HID lighting equipment. Intermittent equipment operation such as welders, motor starting,
and arc furnaces can affect the voltage supplied to lighting equipment so much that people
complain about flickering lights.

Motor starting and short circuits on nearby lines can cause lamp flicker and even large
momentary voltage sags that disrupt sensitive utilization equipment. Arc furnaces and weld-
ers can cause voltage flicker that occurs several times a second. This produces a stroboscopic
effect and can be particularly irritating to people.

Care should be taken to design systems that will not irritate people with flickering lights and
that will not disrupt important industrial and commercial processes.

3.9.1 Motor starting voltage sags

Motors have a high initial inrush current when turned on and impose a heavy load at a low
power factor for a very short time. This sudden increase in the current flowing to the load
causes a momentary increase in the voltage drop along the distribution system, and a corre-
sponding reduction in the voltage at the utilization equipment.

In general, the starting current of a standard motor averages about 5 times the full-load run-
ning current. The approximate values for all ac motors over V 2 hp are indicated by a code
letter on the nameplate of the motor. The values indicated by these code letters are given in
NEMA MG 1 - 1 978 and also in Article 430 of the NEC.

A motor requires about 1 kVA for each motor horsepower in normal operation, so the starting
current of the average motor will be about 5 kVA for each motor horsepower. When the motor
rating in horsepower approaches 5% of the secondary unit substation transformer capacity in
kilovoltamperes, the motor starting apparent power approaches 25% of the transformer

IEEE

Std 141-1993

CHAPTER 3

capacity which, with a transformer impedance voltage of 6-7%, will result in a noticeable
voltage sag on the order of 1%.

In addition, a similar voltage sag will occur in the wiring between the secondary unit substa-
tion and the motor when starting a motor with a full-load current which is on the order of 5%
of the rated current of the circuit. This will result in a full-load voltage drop on the order of 4
or 5%. However, the voltage drop is distributed along the circuit so that maximum sag occurs
only when the motor and the affected equipment are located at the far end of the circuit. As
the motor is moved from the far end to the beginning of the circuit, the voltage drop in the cir-
cuit approaches zero. As the affected equipment is moved from the far end to the beginning of
the circuit, the voltage dip remains constant up to the point of connection of the motor and
then decreases to zero as the equipment connection approaches the beginning of the circuit.

The total voltage sag is the sum of the sag in the secondary unit substation transformer and
the secondary circuit. In the case of very large motors of several hundred to a few thousand
horsepower, the impedance of the supply system should be considered.

Special consideration should always be given when starting larger motors to minimize the
voltage sag so as not to affect the operation of other utilization equipment on the system sup-
plying the motor. Large motors (see table 3-11) may be supplied at medium voltage such as
2400, 4160, 6900, or 13 200 V from a separate transformer to eliminate the voltage dip on the
low-voltage system. However, consideration should be given to the fact that the maintenance
electricians may not be qualified to maintain medium-voltage equipment. A contract with a
qualified electrical firm may be required for maintenance. Standard voltages and preferred
horsepower limits for polyphase induction motors are shown in table 3-11.

Table 3-11 —Standard voltages and preferred horsepower limits
for polyphase induction motors

Motor nameplate voltage

Preferred horsepower limits

115

230

460 and 575

Low-voltage motors

No minimum — 15 hp maximum
No minimum — 200 hp maximum
1 hp minimum — 1000 hp maximum

2300
4000
4500
6000
13 200

Medium- voltage motors

50 hp minimum — 6000 hp maximum
100 hp minimum — 7500 hp maximum
250 hp minimum — no maximum
400 hp minimum — no maximum
1500 hp minimum — no maximum

Source: Based on [B9], table 18-5.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

3.9.2 Flicker limits

Where loads are turned on and off rapidly as in the case of resistance welders, or fluctuate
rapidly as in the case of arc furnaces, the rapid fluctuations in the light output of incandescent
lamps, and to a lesser extent, gaseous discharge lamps, is called flicker. If utilization equip-
ment involving rapidly fluctuating loads is on the order of 10% of the capacity of the second-
ary unit substation transformer and the secondary circuit, accurate calculations should be
made using the actual load currents and system impedances to determine the effect on light-
ing equipment.

Individuals vary widely in their susceptibility to light flicker. Tests indicate that some individ-
uals are irritated by a flicker that is barely noticeable to others. Studies show that sensitivity
depends on how much the illumination changes (magnitude), how often it occurs (frequency),
and the type of work activity undertaken. The problem is further compounded by the fact that
fluorescent and other lighting systems have different response characteristics to voltage
changes. For example, incandescent illumination changes more than fluorescent, but fluores-
cent illumination changes faster than incandescent. Sudden voltage changes from one cycle
to the next are more noticeable than gradual changes over several cycles. Illumination flicker
can be especially objectionable if it occurs often and is cyclical.

Figure 3-8 [B6J shows acceptable voltage flicker limits for incandescent lights used by a large
number of utilities. Two curves show how the acceptable voltage flicker magnitude depends
on the frequency of occurrence. The lower curve shows a borderline where people begin to
detect flicker. The upper curve is the borderline where some people will find the flicker objec-
tionable. At 10 per hour, people begin to detect incandescent lamp flicker for voltage fluctua-
tions larger than 1% and begin to object when the magnitude exceeds 3%.

In using this curve, the purpose for which the lighting is provided needs to be considered. For
example, lighting used for close work such as drafting requires flicker limits approaching the
borderline of visibility curve. For general area lighting such as storage areas, the flicker limits
may approach the borderline of the irritation curve. Note that the effect of voltage flicker
depends on the frequency of occurrence. An occasional dip, even though quite large, is rarely
objectionable.

When objectionable flicker occurs, either the load causing the flicker should be reduced or
eliminated, or the capacity of the supply system increased to reduce the voltage drop caused
by the fluctuating load. In large plants, flicker-producing equipment should be segregated on
separate transformers and feeders so as not to disturb flicker- sensitive equipment.

Objectionable flicker in the supply voltage from the utility should be reported to the utility for
correction. Flexibility in approach and effective communications between the customer and
the utility can be invaluable in resolving potential flicker problems.

3.9.3 Fault clearing voltage sags

Solid-state controllers such as adjustable speed drives, microprocessor controllers, sensors,
and other equipment are often sensitive to momentary voltage sags associated with remote

IEEE

Std 141-1993

CHAPTER 3

30 12 6 3 2 1 30 12 6 3 2 1 .3 .2 .1 .05

MINUTES SECONDS

TIME BETWEEN DIPS

Figure 3-8— Range of observable and objectionable
voltage flicker versus time

electrical short circuits. A short circuit on adjacent plant feeders, a nearby utility distribution
line, or even a transmission line many miles from the sensitive load can cause a noticeable
sag in voltage while short-circuit current is flowing. The voltage sag continues until the cir-
cuit breaker or other fault clearing equipment interrupts the short-circuit current. Consider-
ation should be given to include capabilities to ride through these voltage sags for processes
where sudden, unplanned shutdowns have a significant cost.

The magnitude of the voltage sag depends on the electrical location of the short circuit rela-
tive to the load. Single- and two-phase short circuits are more likely and cause different sag
voltages on each phase. Generally, short circuits on only a few miles of line can cause deep
voltage sags for any one site. However, there are often many miles where short circuits can
cause shallow sags at the same site. This phenomena makes shallow sags many times more
likely than deep sags. Figure 3-9 shows relative probabilities of occurrence compared to the
lowest phase voltage when sags occur. For example, equipment that turns off at 90% of nom-
inal voltage may experience 3.1 times more voltage sag problems than equipment that toler-
ates sags to 80% of nominal.

The duration of voltage sags depends upon the time required to detect and interrupt the short-
circuit current. Typical minimum interruption time for medium- and high-voltage circuit
breakers are 3-5 cycles at 60 Hz while older breakers may be rated for 8 cycles. Some sags

VOLTAGE CONSIDERATIONS

IEEE

Std 141-1993

3.1 TIMES MORE LIKELY

Figure 3-9— Voltage sag probabilities

last even longer because of required time delay for overcurrent coordination. Figure 3-10
shows the probability density of voltage sag duration. The three curves show that half to three
quarters of the measured voltage sags had a duration less than 0.2 s.

Equipment sensitivity to voltage sags generally involves a combination of voltage magnitude
and duration. Both should be considered when specifying equipment performance capabili-
ties during voltage sags.

3.10 Harmonics

Voltage and current on the ideal ac power system have pure single frequency sine wave
shapes. Real power systems have some distortion because an increasing number of loads
require current that is not a pure sine wave. Single- and three-phase rectifiers, adjustable
speed drives, arc furnaces, computers, and fluorescent lights are good examples.

Fourier analysis shows the waveform distortion contains higher frequency components that
are integer multiples of the fundamental frequency. For a 60 Hz power system, the second
harmonic would be 2 • 60 or 120 Hz and the third harmonic would be 3 • 60 or 180 Hz. These
higher frequency components distort the voltage by interacting with the system impedance.
Capacitor failure, premature transformer failure, neutral overloads, excessive motor heating,
relay misoperation, and other problems are possible when harmonics are not properly
controlled.

IEEE

Std 141-1993

CHAPTER 3

Figure 3-10— Voltage sag duration

IEEE Std 519-1992 is a recommended practice for control of harmonics in power systems. It
recommends limits for supply voltage distortion and limits for allowable harmonic current
demands. Chapter 9 of this book also contains more detailed information on harmonics.

3.11 Calculation of voltage drops

Building wiring designers must have a working knowledge of voltage drop calculations, not
only to meet NEC requirements, but also to ensure that the voltage applied to utilization
equipment is maintained within proper limits. The phasor relationships between voltage and
current and resistance and reactance require a working knowledge of trigonometry, especially
for making exact voltage drop computations. Fortunately, most voltage drop calculations are
based on assumed limiting conditions, and approximate formulas are adequate. Also, many
voltage drop computer programs are available that offer speed and accuracy.

3.11.1 General mathematical formulas

The phasor relationships between the voltage at the beginning of a circuit, the voltage drop in
the circuit, and the voltage at the end of the circuit are shown in figure 3-11.

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

SENDING END

I X

SIN <t>

ERROR

Figure 3-11 — Phasor diagram of voltage
relations for voltage-drop calculations

The approximate formula for the voltage drop is

V = //? cos cf) + /A' sin 4>
where

V is the voltage drop in circuit, line to neutral
I is the current flowing in conductor

R is the line resistance for one conductor, in ohms

X is the line reactance for one conductor, in ohms

is the angle whose cosine is the load power factor
cos 4> is the load power factor, in decimals
sin (f> is the load reactive factor, in decimals

The voltage drop V obtained from this formula is the voltage drop in one conductor, one way,
commonly called the line-to-neutral voltage drop. The reason for using the line-to-neutral
voltage is to permit the line-to-line voltage to be computed by multiplying by the following
constants:

Voltage system

Multiply by

Single-phase

Three-phase

1.732

In using this formula, the line current I is generally the maximum or assumed load current-
carrying capacity of the conductor.

IEEE

Std 141-1993

CHAPTER 3

The resistance R is the ac resistance of the particular conductor used and of the particular type
of raceway in which it is installed as obtained from the manufacturer. It depends on the size
of the conductor measured in American Wire Gauge (AWG) for smaller conductors and in
thousands of circular mils (kcmil) for larger conductors, the type of conductor (copper or alu-
minum), the temperature of the conductor (normally 75 °C for average loading and 90 °C for
maximum loading), and whether the conductor is installed in magnetic (steel) or nonmag-
netic (aluminum or nonmetallic) raceway. The resistance opposes the flow of current and
causes the heating of the conductor.

The reactance X is obtained from the manufacturer, it depends on the size and material of the
conductor, whether the raceway is magnetic or nonmagnetic, and on the spacing between the
conductors of the circuit. The spacing is fixed for multiconductor cable but may vary with
single-conductor cables so that an average value is required. Reactance occurs because the
alternating current flowing in the conductor causes a magnetic field to build up and collapse
around each conductor in synchronism with the alternating current. This magnetic field, as it
builds up and falls radially, cuts across the conductor itself and the other conductors of the
circuit, causing a voltage to be induced in each in the same way that current flowing in the
primary of a transformer induces a voltage in the secondary of the transformer. Since the
induced voltage is proportional to the rate of change of the magnetic field, which is maximum
when the current passes through zero, the induced voltage will be a maximum when the cur-
rent passes through zero, or, in vector terminology, lags the current wave by 90 degrees.

4> is the angle between the load voltage and the load current and is obtained by finding the
power factor expressed as a decimal (1 or less) in the cosine section of a trigonometric table
or by using a scientific calculator.

Cos 4> is the power factor of the load expressed in decimals and may be used directly in the
computation of IR cos <f>.

Sin (f> is obtained by finding the angle (j) in a trigonometric table of sines or by using a calcula-
tor. By convention, sin is positive for lagging power factor loads and negative for leading
power factor loads.

IR cos 4> is the resistance component of the voltage drop and IX sin (|) is the reactive compo-
nent of the voltage drop.

For exact calculations, the following formula may be used:

actual voltage drop = e s + IRcosty + /Asin^ - Je 2 s -(IXcos§ - IRsinfy) 2
where the symbols correspond to those in figure 3-11.

3.11.2 Cable voltage drop

Voltage drop tables and charts are sufficiently accurate to determine the approximate voltage
drop for most problems. Table 3-12 contains four sections giving the three-phase line-to-line

VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

voltage drop for 10 000 circuit ampere-feet (A-ft) for copper and aluminum conductors in
both magnetic and nonmagnetic conduit. The figures are for single-conductor cables operat-
ing at 60 °C. However, the figures are reasonably accurate up to a conductor temperature of
75 °C and for multiple-conductor cable. Although the length of cable runs over 600 V is gen-
erally too short to produce a significant voltage drop, table 3-12 may be used to obtain
approximate values. For borderline cases, the exact values obtained from the manufacturer
for the particular cable should be used. The resistance is the same for the same wire size,
regardless of the voltage, but the thickness of the insulation is increased at the higher volt-
ages, which increases the conductor spacing resulting in increased reactance causing increas-
ing errors at the lower power factors. For the same reason, table 3-12 cannot be used for
open-wire or other installations such as trays where there is appreciable spacing between the
individual phase conductors.

In using table 3-12, the normal procedure is as follows: Find the voltage drop for 10 000 A-ft
and multiply this value by the ratio of the actual number of ampere-feet to 10 000. Note that
the distance in feet is the distance from the source to the load.

Example 1. 500 kcmil copper conductor in steel (magnetic) conduit; circuit length 200 ft;
load 300 A at 80% power factor. What is the voltage drop?

Using Section 1 of table 3-12, the intersection between 500 kcmil and 80% power factor
gives a voltage drop of 0.85 V for 10 000 A-ft.

200 ft • 300 A = 60 000 circuit A-ft

(60 000/10 000) • 0.85 = 6 ■ 0.85 = 5.1 V drop

voltage drop, phase-to-neutral = 0.577 ■ 5.1

= 2.9 V

Example 2. AWG No. 12 aluminum conductor in aluminum (nonmagnetic) conduit; circuit
length 200 ft; load 10 A at 70% power factor. What is the voltage drop?

Using Section 4 of table 3-12, the intersection between AWG No. 12 aluminum conductor
and 0.70 power factor is 37 V for 10 000 A-ft.

200 ft • 10 A = 200 circuit A-ft
voltage drop = (2000/10 000) • 37
= 7.4 V

Example 3. Determine the wire size in Example 2 to limit the voltage drop to 3 V. The volt-
age drop in 10 000 A-ft would be as follows:

(10 000/2000) • 3 = 15 V

Using Section 4 of table 3-12, move along the 0.70 power factor line to find the voltage drop
not greater than 15 V. AWG No. 8 aluminum has a voltage drop of 15 V for 10 000 A-ft, so it
is the smallest aluminum conductor in aluminum conduit that could be used to carry 10 A for
200 ft with a voltage drop of not more than 3 V, line-to-line.

Table 3-12— Three-phase line-to-line voltage drop for 600 V single-conductor cable
per 10 000 A-ft (60 °C conductor temperature, 60 Hz)

IEEE

Std 141-1993

CHAPTER 3

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VOLTAGE CONSIDERATIONS

IEEE
Std 141-1993

3.1 1 .3 Busway voltage drop

See Chapter 13 for busway voltage drop tables and related information.

3.1 1 .4 Transformer voltage drop

Voltage-drop curves in figures 3-12 and 3-13 may be used to determine the approximate volt-
age drop in single-phase and three-phase, 60 Hz, liquid-filled, self-cooled, and dry-type trans-
formers. The voltage drop through a single-phase transformer is found by entering the chart
at a kilovoltampere rating three times that of the single-phase transformer. Figure 3-12 covers
transformers in the following ranges:

a) Single-Phase

250-500 kVA, 8.6-15 kV insulation classes
833-1250 kVA, 5-25 kV insulation classes

b) Three-Phase

225-750 kVA, 8.6-15 kV insulation classes
1000-10 000 kVA, 5-25 kV insulation classes

Figure 3-12— Approximate voltage drop curves for
three-phase transformers, 225-10 000 kVA, 5-25 kV

An example of the use of the chart is given in the following:

Example. Find the voltage drop in a 2000 kVA three-phase 60 Hz transformer rated
4160-480 V. The load is 1500 kVA at 0.85 power factor.

Solution. Enter the chart on the horizontal scale at 2000 kVA, extend a line vertically to its
intersection with the 0.85 power factor curve. Extend a line horizontally from this point to the

101

IEEE

Std 141-1993

CHAPTER 3

TRANSFORMER RATING, THREE-PHASE kVA

Figure 3-13— Approximate voltage drop curves for
three-phase transformers, 1500-10 000 kVA, 34.5 kV

left to its intersection with the vertical scale. This point on the vertical scale gives the percent
voltage drop for rated load. Multiply this value by the ratio of actual load to rated load:

percent drop at rated load = 3.67

percent drop at 1500 kVA = 3.67 •

= 2.75

actual voltage drop = 2.75% • 480

= 13.2 V

Figure 3-13 applies to the 34.5 kV insulation class power transformer in ratings from 1500-
10 000 kVA. These curves can be used to determine the voltage drop for transformers in the
46 and 69 kV insulation classes by using appropriate multipliers at all power factors except
unity.

To correct for 46 kV, multiply the percent voltage drop obtained from the chart by 1 .065, and
for 69 kV, multiply by 1.15.

3.11.5 Motor-starting voltage drop

It is characteristic of ac motors that the current they draw on starting is much higher than their
normal running current. Synchronous and squirrel-cage induction motors started on full volt-
age may draw a current as high as seven or eight times their full-load running current. This
sudden increase in the current drawn from the power system may result in excessive drop in

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voltage unless it is considered in the design of the system. The motor-starting load in kilo-
voltamperes, imposed on the power supply system, and the available motor torque are greatly
affected by the method of starting used.

Table 3-13 gives a comparison of several common reduced voltage starting methods. Starting
currents for autotransformers include excitation current for the autotransformer. All voltages,
currents, and starting torques assume 100% of motor nameplate voltage applied to the starter
with no voltage drop in the supply system. Actual motor starting torques vary with the ratio of
actual to nameplate voltage squared. Users should be aware that reduced voltage starting
methods are often used because full voltage starts cause unacceptable voltage drop. Reduced
voltage starting methods cause some voltage drop and starting torques will be less than table
3-13 if the voltage to the starter drops below motor nameplate rating.

Table 3-13— Comparison of motor starting methods

Type of starter
(settings given are the more
common for each type)

Motor terminal
voltage (percent
line voltage)

Starting torque
(percent full-
voltage starting
torque)

Line-current
(percent full-
voltage starting
current)

Full-voltage starter

100

Autotransformer

80% tap

65% tap

50% tap

Resistor starter, single step
(adjusted for motor voltage to
be 80% of line voltage)

Reactor

50% tap

45% tap

37.5% tap

37.5

Part-winding starter (low-speed
motors only)

75% winding

100

50% winding

100

NOTE — See 3.11.5 for more information.

In addition to methods listed in table 3-13, users should consider solid-state soft-start motor
controllers and/or adjustable speed drives.

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3.11.6 Effect of motor starting on generators

Figure 3-14 shows the behavior of the voltage of a generator when an induction motor is
started. Starting a synchronous motor has a similar effect up to the time of pull-in torque. The
case used for this illustration utilizes a full- voltage starting device, and the full- voltage motor
starting load in kilovoltamperes is about 100% of the generator rating. It is assumed for
curves A and B that the generator is provided with an automatic voltage regulator.

100

Ui 80

O 60
>

I 40

0 12 3 4 5 6

TIME (SECONDS)

Motor-starting kVA = 100’’. of
generator rating

A — No initial load on generator
B — 50". initial load on generator
C — No regulator

A FINAL

\ RESTORED

S' /OLTAGE

V /

“'MOTOR

APPROACHING

\ M

INIMUM

FULL SP

EED

\ V
\

OUTAGE

^ C

Figure 3-14— Typical generator voltage behavior
due to full-voltage starting of a motor

The minimum voltage of the generator as shown in figure 3-14 is an important quantity
because it is a determining factor affecting undervoltage devices and contactors connected to
the system and the stalling of motors running on the system. The curves of figure 3-15 can be
used for estimating the minimum voltage occurring at the terminals of a generator supplying
power to a motor being started.

3.11.7 Effect of motor starting on distribution system

Frequently in the case of purchased power, there are transformers and cables between the
starting motor and the generator. Most of the drop in this case is within the distribution equip-
ment. When all the voltage drop is in this equipment, the voltage falls immediately (because
it is not influenced by a regulator as in the generator case) and does not recover until the
motor approaches full speed. Since the transformer is usually the largest single impedance in
the distribution system, it takes almost the total drop. Figure 3-16 has been plotted in terms of
motor starting load in kilovoltamperes that would be drawn if rated transformer secondary
voltage were maintained.

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2 t
1 ?
5 u -

2 o
£ !-
2 z

Z a.
o z

30 40 5060 80 100 150 200 300 400 600800100015002000 4000 60008000

MOTOR STARTING kVA (AT RATED GENERATOR VOLTAGE)

NOTES: (1) The scale of motor horsepower is based on the starting current being
equal to approximately 5.5 times normal.

(2) If there is no initial load, the voltage regulator will restore voltage to 100?t after
dip to values given by curves.

(3) Initial load, if any, is assumed to be of constant-current type.

(4) Generator characteristics are assumed as follows: (a) Generators rated
1000 kVA or less: Performance factor k = 10; transient reactance X d ' = 25°4; synchro-
nous reactance X d = 120%. (b) Generators rated above 1000 kVA: Characteristics for
3600 r/min turbine generators.

Figure 3-15— Minimum generator voltage
due to full-voltage starting of a motor

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MOTOR STARTING kVA ( AT RATED SECONDARY VOLTAGE )

NOTES: (1) The scale of motor horsepower is based on the starting current being
equal to approximately 5.5 times normal.

(2) Short-circuit capacity of primary supply is assumed to be as follows:

Transformer bank load
(kVA)

Primary short-circuit capacity
(kVA)

0-300

25 000

500-1000

50000

1500-3000

100000

3760-10 000

250000

(3) Transformer impedances are assumed to be as follows:

Transformer bank load

Primary bank impedance

(kVA)

(percent)

10-50

3.0

75-150

4.0

200-500

5.0

750-2000

5.5

3000-10 000

6.0

(4) Representative values of primary system voltage drop, expressed as a fraction
of total drop, for the assumed conditions, are as follows:

Transformer bank load

System drop

(kVA)

Total drop

100

0.09

1000

0.25

10 000

0.44

Figure 3-16— Approximate voltage drop in a transformer
due to full-voltage starting of a motor

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3.12 References

This standard shall be used in conjunction with the following publications:

ANSI C57. 12.20-1988, American National Standard Requirements for Overhead-Type Dis-
tribution Transformers 67 000 Volts and Below, 500 kVA and Smaller.

ANSI C84. 1-1989, American National Standard Voltage Ratings for Electric Power Systems
and Equipment (60 Hz).

ANSI C92.2-1987, American National Standard Preferred Voltage Ratings for Alternating-
Current Electrical Systems and Equipment Operating at Voltages above 230 Kilovolts
Nominal for Power Systems.

ANSI/NFPA 70-1993, National Electric Code. 4

CAN3-C235-83, Preferred Voltage Levels for AC Systems, 0 to 50 000 V (Canadian Stan-
dards Association). 5

IEEE Std 100-1992, The New IEEE Standard Dictionary of Electrical and Electronics Terms
(ANSI).

IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and Commer-
cial Power Systems (IEEE Green Book) (ANSI).

IEEE Std 242-1986 (Reaff 1991), IEEE Recommended Practice for Protection and Coordina-
tion of Industrial and Commercial Power Systems (IEEE Buff Book) (ANSI).

IEEE Std 446-1987, IEEE Recommended Practice for Emergency and Standby Power Sys-
tems for Industrial and Commercial Applications (IEEE Orange Book) (ANSI).

IEEE Std 519-1992, IEEE Recommended Practices and Requirements for Harmonic Control
in Electric Power Systems.

IEEE Std 1100-1992, IEEE Recommended Practice for Powering and Grounding Sensitive
Electronic Equipment (IEEE Emerald Book).

NEMA MG 1-1993, Motors and Generators. 6

3 ANSI publications are available from the Sales Department, American National Standards Institute, 1 1 West 42nd
Street, 13th Floor, New York, NY 10036, USA.

4 NFPA publications are available from Publication Sales, National Fire Protection Association. 1 Batterymarch Park,
P.O. Box 9101, Quincy. MA 02269-9101, USA.

5 CSA publications are available from the Canadian Standards Association (Standards Sales), 178 Rexdale Blvd.,
Rexdale, Ontario, Canada M9W 1R3.

6 NEMA publications can be obtained from the Sales Department, American National Standards Institute, or from the
National Electrical Manufacturers Association, 2101 L Street, NW, Washington, DC 20037.

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3.13 Bibliography

[B 1 ] Arnold, R. E., “NEMA Suggested Standards for Future Design of AC Integral Horse-
power Motors,” IEEE Transactions on Industry and General Applications , vol. IGA-6,
pp. 110-114, Mar./Apr. 1970.

[B2] Brereton, D. S., and Michael, D. T., “Developing a New Voltage Standard for Industrial
and Commercial Power Systems,” Proceedings of the American Power Conference , vol. 30,
pp. 733-751, 1968.

[B3] Brereton, D. S., and Michael, D. T., “Significance of Proposed Changes in AC System
Voltage Nomenclature for Industrial and Commercial Power Systems: I— Low- Voltage
Systems,” IEEE Transactions on Industry and General Applications, vol. IGA-3, pp. 504-
513, Nov./Dec. 1967.

[B4] Brereton, D. S., and Michael, D. T., “Significance of Proposed Changes in AC System
Voltage Nomenclature for Industrial and Commercial Power Systems: II— Medium- Voltage
Systems,” IEEE Transactions on Industry and General Applications, vol. IGA-3, pp. 514-520,
Nov./Dec. 1967.

[B5 ] Conrad, L., Grigg, C., and Little, K., “Predicting and Preventing Problems Associated
with Remote Fault Clearing Voltage Dips,” IEEE Transactions on Industry Applications,
vol. 27, no. 1, PP- 167-172, Jan./Feb. 1991.

[B6] Electric Utility Engineering Reference Book, vol. 3: Distribution Systems. Trafford, PA:
Westinghouse Electric Corporation, 1965.

[B7] Goldstein, M., and Speranza, R, “The Quality of U.S. Commercial AC Power,” IEEE
paper CH1818-4/82/000-00028, 1982.

[B8] Gulachenski, E., “New England Electric’s Power Quality Research Study,” Proceedings
of the Second International Conference on Power Quality, Palo Alto, California: Electric
Power Research Institute, pp. F-1L1-10, 1992.

[B9] IEEE Distribution Subcommittee Working Group of Voltage Flicker, “Flicker Limita-
tions of Electric Utilities,” 1985.

[B 10J Linders, J. R., “Effects of Power Supply Variations on AC Motor Characteristics,” Con-
ference Record, 6th Annual Meeting of the IEEE Industry and General Applications Group,
IEEE 71 Cl -IGA, pp. 1055-1068, 1971.

[Bll| Michael, D. T., “Proposed Design Standard for the Voltage Drop in Building Wiring
for ”Low-Voltage Systems,” IEEE Transactions on Industry and General Applications,
vol. IGA-4, pp. 30-32, Jan./Feb. 1968.

[B 12] Standard Handbook for Electrical Engineers, 10 Ed., Table 18-5. New York: McGraw-

Hill.

108

Chapter 4

Short-circuit current calculations

4.1 Introduction

Even the best designed electric systems occasionally experience short circuits resulting in
abnormally high currents. Overcurrent protective devices, such as circuit breakers and fuses,
should isolate faults at a given location safely with minimal circuit and equipment damage
and minimal disruption of the plant’s operation. Other parts of the system, such as cables,
busways, and disconnecting switches, shall be able to withstand the mechanical and thermal
stresses resulting from maximum flow of short-circuit current through them. The magnitudes
of short-circuit currents are usually estimated by calculation, and equipment is selected using
the calculation results.

The current flow during a short circuit at any point in a system is limited by the impedance of
circuits and equipment from the source or sources to the point of fault. It is not directly
related to the size of the load on the system. However, additions to the system that increase its
capacity to handle a growing load, such as more or larger incoming transformers from a util-
ity, while not affecting the normal load at some existing locations in the system, may drasti-
cally increase the short-circuit currents at those locations. Whether an existing system is
expanded or a new system is installed, available short-circuit currents should be determined
for proper application of overcurrent protective devices.

Calculated maximum short-circuit currents are nearly always required. In some cases,
the minimum sustained values are also needed to check the sensitivity requirements of the
current-responsive protective devices.

This chapter has three purposes:

a) To present some fundamental considerations of short-circuit current calculations;

b) To illustrate some commonly used methods of making these calculations with typical
examples;

c) To furnish typical data that can be used in making short-circuit current calculations.

The size and complexity of many modern industrial systems may make longhand short-
circuit current calculations impractically time-consuming. Computers are generally used
for major short-circuit studies. Whether or not computers are available, a knowledge of
the nature of short-circuit currents and calculating procedures is essential to conduct such
studies.

4.2 Sources of fault current

Fundamental frequency currents that flow during a short circuit come from rotating electric
machinery. (Charged power capacitors can also produce extremely high transient short-circuit

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discharge currents, but they are of natural frequency much higher than power frequency and
usually of such short duration that the calculated power frequency short-circuit duty current
is not significantly increased by adding the capacitor discharge. Discharge currents are calcu-
lated as described for RLC circuits in many electrical engineering texts and an appropriate
RLC circuit can be based on power system data.) Rotating machinery in industrial plant
short-circuit calculations may be analyzed in five categories:

a) Synchronous generators

b) Synchronous motors and condensers

c) Induction machines

d) Electric utility systems

e) Adjustable speed ac induction or dc motors with solid-state ac power supply
equipments

The fault current from each rotating machinery source is limited by the impedance of the
machine and the impedance between the machine and the short circuit. Fault currents gener-
ally are not dependent upon the pre-fault loading of the machine. The impedance of a rotating
machine is not a simple value but is complex and variable with time.

4.2.1 Synchronous generators

If a short circuit is applied to the terminals of a synchronous generator, the short-circuit cur-
rent starts out at a high value and decays to a steady-state value some time after the inception
of the short circuit. Since a synchronous generator continues to be driven by its prime mover
and to have its field externally excited, the steady-state value of short-circuit current will per-
sist unless interrupted by some switching means. An equivalent circuit consisting of a con-
stant driving voltage in series with an impedance that varies with time (figure 4-1) is used to
represent this characteristic. The varying impedance consists primarily of reactance.

Figure 4-1 —Equivalent circuit for generators and motors
E = (driving voltage, X varies with time)

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For purposes of short-circuit current calculations, industry standards have established three
specific names for values of this variable reactance, called subtransient reactance, transient
reactance, and synchronous reactance.

X d " = subtransient reactance; determines current during first cycle after fault occurs. In about
0.1 s reactance increases to

X d ' = transient reactance; assumed to determine current after several cycles at 60 Hz. In about
0.5 to 2 s reactance increases to

X d = synchronous reactance; this is the value that determines the current flow after a steady-
state condition is reached.

Because most short-circuit interrupting devices, such as circuit breakers and fuses, operate
well before steady-state conditions are reached, generator synchronous reactance is seldom
used in calculating fault currents for application of these devices.

Synchronous generator data available from some manufacturers includes two values for
direct axis subtransient reactance— for example, subtransient reactances X dv " (at rated volt-
age, saturated, smaller) and X di " (at rated current, unsaturated, larger). Because a short-
circuited generator may be saturated, and for conservatism, the X dv " value is used for
short-circuit current calculations.

4.2.2 Synchronous motors and condensers

Synchronous motors supply current to a fault much as synchronous generators do. When a
fault causes system voltage to drop, the synchronous motor receives less power from the sys-
tem for rotating its load. At the same time, the internal voltage causes current to flow to the
system fault. The inertia of the motor and its load acts as a prime mover and, with field exci-
tation maintained, the motor acts as a generator to supply fault current. This fault current
diminishes as the magnetic field in the machine decays.

The generator equivalent circuit is used for synchronous motors. Again, a constant driving
voltage and the same three reactances, X/', X /, and X^, are used to establish values of current
at three points in time.

Synchronous condensers are treated in the same manner as synchronous motors.

4.2.3 Induction machines

A squirrel-cage induction motor will contribute current to a power system short circuit. This
is generated by inertia driving the motor in the presence of a field flux produced by induction
from the stator rather than from a dc field winding. Since this flux decays on loss of source
voltage caused by a fault at the motor terminals, the current contribution of an induction
motor to a terminal fault reduces and disappears completely after a few cycles. Because field
excitation is not maintained, there is no steady-state value of fault current as for synchronous
machines.

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Again, the same equivalent circuit is used, but the values of transient and synchronous reac-
tance approach infinity. As a consequence, induction motors are assigned only a subtransient
value of reactance X d ". This value varies upward from the locked rotor reactance to account
for the decay of the motor current contribution to the short circuit.

For short-circuit current calculations, an induction generator can be treated the same as an
induction motor. Wound-rotor induction motors normally operating with their rotor rings
short-circuited will contribute short-circuit current in the same manner as a squirrel-cage
induction motor. Occasionally, large wound-rotor motors operated with some external resis-
tance maintained in their rotor circuits may have sufficiently low short-circuit time constants
that their short-circuit current contribution is not significant and may be neglected. A specific
investigation should be made to determine whether to neglect the contribution from a wound-
rotor motor.

4.2.4 Electric utility systems

The remote generators of an electric utility system are a source of short-circuit current often
delivered through a supply transformer. The generator-equivalent circuit can be used to repre-
sent the utility system. The utility generators are usually remote from the industrial plant. The
current contributed to a short circuit in the remote plant appears to be merely a small increase
in load current to the very large central station generators, and this current contribution tends
to remain constant. Therefore, the electric utility system is usually represented at the plant by
a single valued equivalent impedance referred to the point of connection.

4.2.5 Adjustable speed ac induction or dc motors with solid-state ac power
supply equipments

Some adjustable speed ac induction or dc motors, speed controlled by adjusting the fre-
quency or dc voltage of solid-state ac power supply equipments, can, under certain condi-
tions, contribute current from the motors to a short circuit on the incoming ac electric power
system. The design of the power supply equipment determines whether a current can or can-
not be “backfed” from the motors. When it can, the power supply operating mode at the time
of the power system short circuit usually determines the magnitude and duration of the back-
fed current. For some motors, the duration is limited by power supply equipment protective
functions to less than one cycle of ac power frequency. The adjustable frequency or dc volt-
age power supply manufacturer should be consulted for information on whether adjustable
speed ac induction or dc motors can contribute backfeed current to ac power system short cir-
cuits, and if so, under what operating conditions and how much.

4.3 Fundamentals of short-circuit current calculations

Ohm’s law, I = E/Z, is the basic relationship used in determining I, the short-circuit current,
where E is the driving voltage of the source, and Z is the impedance from the source to the
short circuit including the impedance of the source.

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Most industrial systems have multiple sources supplying current to a short circuit since each
motor can contribute. One step in short-circuit current calculation is the simplification of the
multiple-source system to the condition where the basic relationship applies.

4.3.1 Purpose of calculations

System and equipment complexity and the lack of accurate parameters make precise calcula-
tions of short-circuit currents exceedingly difficult, but extreme precision is unnecessary. The
calculations described provide reasonable accuracy for the maximum and minimum limits of
short-circuit currents. These satisfy the usual reasons for making calculations.

The maximum calculated short-circuit current values are used for selecting interrupting
devices of adequate short-circuit rating, to check the ability of components of the system to
withstand mechanical and thermal stresses, and to determine the time-current coordination of
protective relays. The minimum values are used to establish the required sensitivity of protec-
tive relays. Minimum short-circuit values are sometimes estimated as fractions of the maxi-
mum values. If so, it is only necessary to calculate the maximum values of short-circuit
current.

For calculating the maximum short-circuit current, the industrial electric power system
should have the largest expected number of connected rotating machines (usually with the
system at full future load).

4.3.2 Type of short circuit

In an industrial system, the three-phase short circuit is frequently the only one considered,
since this type of short circuit generally results in maximum short-circuit current.

Line-to-line short-circuit currents are approximately 87% of three-phase short-circuit cur-
rents. Line-to-ground short-circuit currents can range in utility systems from a few percent to
possibly 125% of the three-phase value. In industrial systems, line-to-ground short-circuit
currents higher than three phase are rare except when bolted short circuits are near the wye
windings with a solidly grounded neutral of either generators or two winding, delta-wye,
core-type transformers.

Assuming a three-phase short-circuit condition also simplifies calculations. The system,
including the short circuit, remains symmetrical about the neutral point, whether or not the
neutral point is grounded and regardless of wye or delta transformer connections. The bal-
anced three-phase short-circuit current can be calculated using a single-phase equivalent cir-
cuit that has only line-to-neutral voltage and impedance.

In calculating the maximum short-circuit current, it is assumed that the short-circuit connec-
tion has zero impedance (is “bolted”) with no current-limiting effect due to the short circuit
itself. It should be recognized, however, that actual short circuits often involve arcing, and
variable arc impedance can reduce low- voltage short-circuit current magnitudes appreciably.

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In low-voltage systems, the minimum values of short-circuit current are sometimes calculated
from known effects of arcing. Analytical studies indicate that the sustained arcing short-cir-
cuit currents, in per unit of bolted fault values, may be typically as low as

a) 0.89 at 480 V and 0.12 at 208 V for three-phase arcing

b) 0.74 at 480 V and 0.02 at 208 V for line-to-line single-phase arcing

c) 0.38 at 277 V and 0.01 at 120 V for line-to-neutral single-phase arcing

4.3.3 Basic equivalent circuit

The basic equation finds the current of a simple circuit having one voltage source and one
impedance. In the basic equation, the voltage E represents a single overall system driving
voltage, which replaces the array of individual unequal generated voltages acting within
separate rotating machines. This voltage is equal to the prefault voltage at the point of short-
circuit connection. The impedance Z is a network reduction of the impedances representing
all significant elements of the power system connected to the short-circuit point including
source internal impedances.

This equivalent circuit of the power system is a valid circuit transformation in accordance
with Thevenin’s theorem. It permits a determination of short-circuit current corresponding to
the values of system impedances used.

Ordinarily, the prefault voltage is taken as the system nominal voltage at the point of short
circuit because this is close to the maximum operating voltage under fully loaded system con-
ditions, and therefore the short-circuit currents will approach maximum. Higher than nominal
voltage might be used in an unusual case when full load system voltage is observed to be
above nominal.

The single-phase representation of a three-phase balanced system uses per-phase impedances
and the line-to-neutral system driving voltage. Line-to-neutral voltage is line-to-line voltage
divided by J3 .

Calculations may use impedances in ohms and voltages in volts, or both in per unit. Per unit
calculations simplify short-circuit studies for industrial systems that involve voltages of
several levels. When using the per unit system, the driving voltage is equal to 1.0 per unit if
voltage bases are equal to system nominal voltages.

The major elements of impedance must always be included in a short-circuit current calcula-
tion. These are impedances of transformers, busways, cables, conductors, and rotating
machines. There are other circuit impedances, such as those associated with circuit breakers,
wound or bar-type current transformers, bus structures, and bus connections, that are usually
small enough to be neglected in medium- or high-voltage-system short-circuit calculations,
because the accuracy of the calculation is not generally affected. Omitting them provides
slightly more conservative (higher) short-circuit currents. However, in low-voltage systems,
and particularly at 208 V, there are cases where impedance of these elements is appreciable
and inclusion can significantly reduce the calculated short-circuit current.

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Also, the usual practice is to disregard the presence of static loads (such as lighting and elec-
tric heating) in the network, despite the fact that their associated impedance is actually con-
nected in shunt with other network branches. This approach is considered valid since usually
the relatively high power factor static load impedances are large and approximately 90° out-
of-phase compared to the impedances of the other highly reactive parallel branches of the
network.

In ac circuits, the impedance Z is the vector sum of resistance R and reactance X. It is always
acceptable to calculate short-circuit currents using vector impedances in the equivalent cir-
cuit. For most short-circuit current magnitude calculations at medium or high voltage, and for
a few at low voltage, when the reactances are much larger than the resistances, it is suffi-
ciently accurate, conservative, and simpler to ignore resistances and use reactances only.

For many low-voltage calculations, however, resistances should not be ignored because the
calculated currents would be overconservative.

Resistances are definitely needed for calculations of X/R ratios when applying high- and
medium-voltage circuit breakers, but they are analyzed in a network separate from the reac-
tance network.

4.4 Restraints of simplified calculations

The short-circuit calculations described in this chapter are a simple E/Z evaluation of exten-
sive electric power system networks. Before describing the step-by-step procedures in mak-
ing these calculations, it is appropriate to review some of the restraints imposed by the
simplification.

4.4.1 Impedance elements

When an ac electric power circuit contains resistance R, inductance L, and capacitance C,
such as the series connection shown in figure 4-2, the expression relating current to voltage
includes the terms shown in figure 4-2. A textbook determination of the current magnitude
requires the solution of a differential equation.

d 2 Q
' dt 2

dQ Q

+ R — + - + E 0
dt C

Figure 4-2— Series RLC circuit

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If two important restraints are applied to this series circuit, the following simple equation
using vector impedances (XL = co L and XC = 1/co C) is valid:

E = I

R + jl (s>L

co C,

These restraints are that, first, the electric driving force be a sine wave and, second, the
impedance coefficients R, L, and C be constants. Unfortunately, in short-circuit calculations
these restraints may be invalidated. A major reason for this is switching transients.

4.4.2 Switching transients

The vector impedance analysis recognizes only the steady-state sine wave electrical quanti-
ties and does not include the effects of abrupt switching. Fortunately, the effects of switching
transients can be analyzed separately and added. (An independent solution can be obtained
from a solution of the formal differential equations.)

In the case of only resistance R (figure 4-3), the closure of switch .S' IT causes the current to
immediately assume the value that would exist in the steady state. No transient adder is
needed.

Figure 4-3— Switching Transient R

In the case of all inductance L (figure 4-4), an understanding of the switching transient can
best be acquired using the following expression:

„ T dl dl E

dt dt L

This expression tells us that the application of a driving voltage to an inductance will create a
time rate of change in the current magnitude. The slope of the current-time curve in the
inductance will be equal to the quantity E/L.

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Figure 4-4— Switching transient L

The steady-state current curve is displayed at the right hand side of the graph of figure 4-4. It
lags the voltage wave by 90° and is rising at the maximum rate in the positive direction when
the voltage is at the maximum positive value. It holds at a fixed value when the driving volt-
age is zero. This curve is projected back to the time of circuit switching (dashed curve). Note
that at the instant the switch is closed, the steady-state current would have been at a negative
value of about 90% of crest value. Since the switch was previously open, the true circuit cur-
rent must be zero. After closing the switch, the current wave will display the same slope as
the steady-state wave. This is the solid line current curve beginning at the instant of switch
closing. Note that the difference between this curve and the steady state is a positive dc com-
ponent of the same magnitude that the steady-state wave would have had at the instant of
switch closing, in the negative direction. Thus the switching transient takes the form of a dc
component whose value may be anything between zero and the steady-state crest value,
depending on the angle of switch closing.

If the circuit contained no resistance, the current would continue forever in the displaced
form. The presence of resistance causes the dc component to be dissipated exponentially. The
complete expression for the current would take the following form:

/ = — — sin(cor) + I d e ( -~ R, ') /L
jmL

The presence of dc components may introduce unique problems in selective coordination
between some types of overcurrent devices. It is particularly important to bear in mind that
these transitory currents are not disclosed by the vector impedance circuit solution, but must
be introduced artificially by the analyst or by the guide rules followed.

4.4.3 Decrement factor

The value at any time of a decaying quantity, expressed in per unit of its initial magnitude, is
the decrement factor for that time. Refer to figure 4-5 for decrement factors of an exponential
decay.

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e -Rt/L _ g-t/t'

t ' = L/R (TIME CONSTANT)

Figure 4-5— Decrement factor

The significance of the decrement factor can be better understood if the exponential is
expressed in terms of the time constant. If, as indicated in figure 4-5, the exponent is
expressed as -tit' with the time variable t in the numerator and the rest combined as a single
constant t' (called the time constant) in the denominator, the transitory quantity begins its
decay at a rate that would cause it to vanish in one time constant. The exponential character
of the decay results in a remnant of 36.8% remaining after an elapsed time equal to one time
constant. Any value of the transitory term selected at, say, time t will be reduced to 0.368 of
that value after a subsequent elapsed time equal to one time constant. A transitory quantity of
magnitude 1.0 at time zero would be reduced to a value of 0.368 after an elapsed time equal
to one time constant, to a value of 0.135 after an elapsed time equal to two time constants,
and to a value of 0.05 after an elapsed time equal to three time constants.

4.4.4 Multiple switching transients

The analyst usually assumes that the switching transient will occur only once during one
excursion of short-circuit current flow. An examination of representative oscillograms of
short-circuit currents will often display repeated instances of momentary current interrup-
tions. At times, an entire half cycle of current will be missing. In other cases, especially in
low-voltage circuits, there may be a whole series of chops and jumps in the current pattern. A
switching interrupter, especially when switching a capacitive circuit, may be observed to
restrike two or perhaps three times before final interruption. The restrike generally occurs
when the voltage across the switching contacts is high. It is entirely possible that switching
transients, both simple dc and ac transitory oscillations, may be reinserted in the circuit cur-
rent a number of times during a single incident of short-circuit current flow and interruption.
The analyst should remain mindful of possible trouble.

4.4.5 Practical impedance network synthesis

One approach to an adequate procedure for computing the phase A current of a three-phase
system is indicated in figure 4-6. For each physical conducting circuit, the voltage drop is
represented as the sum of the self-impedance drops in the circuit and the complete array of

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mutually coupled voltage drops caused by current flow in other coupled circuits. The proce-
dure is complex even in those instances where the current in both the neutral and ground con-
ductors is zero.

* Z AA M BA M CA m NA M GA

The simplified analytical approach to this problem assumes balanced symmetrical loading of
a symmetrical polyphase system. With a symmetrical system operating with a symmetrical
loading, the effects of all mutual couplings are similarly balanced. What is happening in
phase A in the way of self- and mutually coupled voltages is also taking place in phase B with
exactly the same pattern, except displaced 120°, and it is also taking place in phase C with the
same pattern, except displaced another 120°. The key to the simplification is the fact that the
ratio of the total voltage drop in one phase circuit to the current in that phase circuit is the
same in all three phases of the system. Thus it appears that each phase possesses a firm
impedance value common with the other phases. This unique impedance quantity is identified
as the single phase line-to-neutral impedance value. Any one line-to-neutral single phase seg-
ment of the system may be sliced out for the analysis, since all are operating with the same
load pattern.

The impedance diagram of the simplified concept appears in figure 4-7. The need to deal with
mutual coupling has vanished. Since each phase circuit presents identically the same infor-
mation, it is common to show only a single phase segment of the system in a one line diagram
as illustrated simply by figure 4-1. The expressions below the sketch in figure 4-7 contain
some unfamiliar terms. Their meaning will be discussed in succeeding paragraphs.

One restraint associated with this simple analytical method is that all phases of the system
share symmetrical loading. While a three-phase short circuit would satisfy this restraint,
some short-circuit problems that must be solved are not balanced. For these unbalanced
short-circuit problems, the concept of symmetrical components is used for solution. This con-
cept discloses that any conceivable condition of unbalanced loading can be correctly synthe-
sized by the use of appropriate magnitudes and phasing of several systems of symmetrical
loading. In a three-phase system, with a normal phase separation of 120°, there are just three

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Impedance identity for each symmetrical pattern:
Positive sequence Z G\

Negative sequence Z G2

Zero sequence Z G0 + ^ Z GR *

* Based on zero current in conductor N.

Ea - E a'= Lit Z G\ + ^42 Z G2 + I AO ( Z G0 + 3 Z GR )

Figure 4-7— Three-phase, four-wire circuit, balanced symmetrical loading

possible symmetrical loading patterns. These can be quickly identified with the aid of figure
4-8. Loadings of the three-phase windings A, B, and C must follow each other in sequence,
separated by some multiple of 120°. In figure 4-8(a) they follow each other with a 120° sepa-
ration, in figure 4-8(b) with a 240° separation, and in figure 4-8(c) with a 360° separation.
Note that separation angles of any other multiples of 120° will duplicate one of the three
already shown. These loading patterns satisfy the restraints demanded by the analytical
method to be used.

Note that figure 4-8(a), identified as the positive sequence, represents the normal balanced
operating mode. Thus there are only two sequence networks that differ from the normal. Fig-
ure 4-8(b), called the negative sequence, identifies a loading pattern very similar to the posi-
tive sequence, except that the electrical quantities come up with the opposite sequence. A
current of this pattern flowing in a motor stator winding would create a normal speed rotating
field, but with backward rotation. The pattern of figure 4-8(c), called the zero sequence, rep-
resents the case in which the equal currents in each phase are in phase. Each phase current
reaches its maximum in the same direction at the same instant.

It is understandable that machine interwinding mutual coupling and other mutual coupling
effects will be different in the different sequence systems. Hence it is likely that the per phase
impedance of the negative and zero sequence systems will differ from that of the positive
sequence. Currents of zero sequence, being in phase, do not add up to zero at the end terminal
as do both the positive and negative sequence currents. They add arithmetically and return to

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The individual phase quantities A, B,
with an angular spacing of

Positive sequence
Negative sequence
Zero sequence

and C follow each other

120 °

240°

360°

Figure 4-8— Three-phase symmetrical load patterns
applicable to a three-phase system

the source via an additional circuit conductor. The zero-sequence voltage drop of this return
conductor is accounted for in the zero-sequence impedance value. With this understanding of
the three symmetrical loading patterns, the significance of the notes below the sketch in figure
4-7 becomes clear.

The simplifications in analytical procedures accomplished by the per-phase line-to-neutral
balanced system concepts carry with them some important restraints:

a) The electric power system components shall be of symmetrical design pattern.

b) The electric loading imposed on the system shall be balanced and symmetrical.

Wherever these restraints are violated, it is necessary to construct substantially hybrid net-
work interconnections that bridge the zones of unbalanced conditions. In the field of short-
circuit current calculations, the necessary hybrid interconnections of the sequence networks
to accommodate the various unbalanced fault connections can be found in a variety of pub-
lished references. It is harder to find the necessary hybrid interconnections to accommodate a
lack of symmetry in the circuit geometry, as needed for an open delta transformer bank, an
open line conductor, etc.

4.4.6 Other analytical tools

A large number of valid network theorems can be used effectively to simplify certain kinds of
problems encountered in short-circuit analysis. These are described and illustrated in many
standard texts on ac circuit analysis; see Chapter 8 of IEEE Std C37.13-1990 1 . Of exceptional
importance are Thevenin’s theorem and the superposition theorem. Thevenin’s theorem
allows an extensive complex single-phase network to be reduced to a single driving voltage in
series with a single impedance, referred to the particular bus under study. The superposition

'information on references can be found in 4.9.

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theorem allows the local effect of a remote voltage change in one source machine to be eval-
uated by impressing the magnitude of the voltage change, at its point of origin, on the com-
plete impedance network; the current reading in an individual circuit branch is treated as an
adder to the prior current magnitude in that branch. These analytical tools, like the others,
have specific restraints that must be observed to obtain valid results.

4.4.7 Respecting the imposed restraints

Throughout this discussion, emphasis has been placed on the importance of respecting the
restraints imposed by the analytical procedure in order to obtain valid results. Mention has
been made of numerous instances in short-circuit analysis where it is necessary to artificially
introduce appropriate corrections when analytical restraints have been violated. One remain-
ing area associated with short-circuit analysis involves variable impedance coefficients.
When an arc becomes a series component of the circuit impedance, the R it represents is not
constant. If it is 100 Q at a current of 1 A, it might be 0.1 £2 at a current of 1000 A. During
each half-cycle of current flow, the arc resistance might traverse this range. It is difficult to
determine a proper value to insert in the 60 Hz network. Correctly setting this value of R does
not compensate for the violation of the restraint that demands that R be a constant. The varia-
tion in R lessens the impedance to high-magnitude current, which results in a wave shape of
current that is much more peaked than a sine wave. The current now contains harmonic
terms. Since they result from a violation of analytical restraints, they will not appear in the
calculated results. Their character and magnitude can be determined by other means and the
result artificially introduced into the solution for short-circuit current. A similar type of non-
linearity may be encountered in electromagnetic elements in which iron plays a part in setting
the value of L. If the ferric parts are subject to large excursions of magnetic density, the value
of L may be found to drop substantially when the flux density is driven into the saturation
region. As with variable R, the effect of this restraint violation will result in the appearance of
harmonic components in the true circuit current.

4.4.8 Conclusions

The purpose of this review of fundamentals is to obtain a better understanding of the basic
complexities involved in ac system short-circuit current calculations. In dealing with the day-
to-day practical problems, the analyst should adopt the following goals:

a) Select the optimum location and type of fault to satisfy the purpose of the calculation.

b) Establish the simplest electric circuit model of the problem that will both accomplish
this purpose and minimize the complexity of the solution.

c) Recognize the presence of system conditions that violate the restraints imposed by
the analytical methods in use.

d) Artificially inject corrections in computed results to compensate if these conditions
are large enough to be significant.

Some conclusions of the preceding section apply to the simplified procedures of this chapter.
A balanced three-phase fault has been assumed and a simple equivalent circuit has been
described. The current E/Z calculated with the equivalent circuit is an alternating symmetrical
rms current, because E is the rms voltage. Within specific constraints to be discussed, this

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symmetrical current may be directly compared with equipment ratings, capabilities, or per-
formance characteristics that are expressed as symmetrical rms currents.

The preceding analysis of inductive circuit switching transients indicates that simplified pro-
cedures should recognize and account for asymmetry as a system condition. The correction to
compensate for asymmetry considers the asymmetrical short-circuit current wave to be com-
posed of two components. One is the ac symmetrical component E/Z. The other is a dc com-
ponent initially of maximum possible magnitude, equal to the peak of the initial ac
symmetrical component, or, alternatively, of the magnitude corresponding to the highest peak
(crest), assuming that the fault occurs at the point on the voltage wave where it creates this
condition. At any instant after the fault occurs, the total current is equal to the sum of the ac
and dc components (figure 4-9).

Figure 4-9— Typical system fault current

Since resistance is always present in an actual system, the dc component decays to zero as the
stored energy it represents is expended in I~R loss. The decay is assumed to be an exponen-
tial, and its time constant is assumed to be proportional to the ratio of reactance to resistance
( X/R ratio) of the system from source to fault. As the dc component decays, the current grad-
ually changes from asymmetrical to symmetrical (figure 4-9).

Asymmetry is accounted for in simplified calculating procedures by applying multiplying
factors to the alternating symmetrical current. A multiplying factor is selected that obtains a
resulting estimate of the total (asymmetrical) rms current or the peak (crest) current, as
appropriate for comparison with equipment ratings, capabilities, or performance characteris-
tics that are expressed as total (asymmetrical) rms currents or peak (crest) currents.

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The alternating symmetrical current may also decay with time, as indicated in the discussion
of sources of short-circuit current. Changing the impedance representing the machine prop-
erly accounts for ac decay of the current to a short circuit at rotating-machine terminals. The
same impedance changes are assumed to be applicable when representing rotating machines
in extensive power systems.

4.5 Detailed procedure

A significant part of the preparation for a short-circuit current calculation is establishing the
impedance of each circuit element and converting impedances to be consistent with each
other for combination in series and parallel. Sources of impedance values for circuit elements
are nameplates, handbooks, manufacturers’ catalogs, tables included in this chapter, and
direct contact with the manufacturer.

Two established consistent forms for expressing impedances are ohms and per unit (per unit
differs from percent by a factor of 100). Individual equipment impedances are often given in
percent, which makes comparisons easy, but percent impedances are rarely used without con-
version in system calculations. In this chapter, the per unit form of impedance is used because
it is more convenient than the ohmic form when the system contains several voltage levels.
Impedances expressed as per unit on a defined base can be combined directly, regardless of
how many voltage levels exist from source to fault. To obtain this convenience, the base volt-
age at each voltage level must be related according to the turns ratios of the interconnecting
transformers.

In the per-unit system, there are four base quantities: base apparent power in voltamperes,
base voltage, base current, and base impedance. The relationship of base, per unit, and actual
quantities is as follows:

per-unit quantity (voltage, current, etc.)

actual quantity
base quantity

Usually a convenient value is selected for base apparent power in voltamperes, and a base
voltage at one level is selected to match the transformer rated voltage at that level. Base volt-
ages at other levels are then established by transformer turns ratios. Base current and base
impedance at each level are then obtained by standard relationships. The following formulas
apply to three-phase systems, where the base voltage is the line-to-line voltage in volts or
kilovolts and the base apparent power is the three-phase apparent power in kilovoltamperes or
megavoltamperes :

, w base kVA (1000) base kVA

base current (amperes) = 1 =

Jl (base V) J3 (base kV)

= base MYA 10 6 = base MYA (1000)
V3 (base V) J3 (base kV)

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base impedance (ohms)

base V _ (baseV) 2
V3 (base A) base kVA (1000)

= (base kV) 2 (1000) = (base kV) 2
base kVA base MVA

Impedances of individual power system elements are usually obtained in forms that require
conversion to the related bases for a per-unit calculation. Cable impedances are generally
expressed in ohms. Converting to per unit using the indicated relationships leads to the fol-
lowing simplified formulas, where the per-unit impedance is Z pu :

actual impedance in ohms ((base MVA)
(base kV) 2

actual impedance in ohms (base kVA)
(base kV) 2 (1000)

Transformer impedances are in percent of self-cooled transformer ratings in kilovoltamperes
and are converted using the following:

percent impedance (base kVA)
kVA rating ( 100)

percent impedance (10) (base MVA)
kVA rating

Motor reactance may be obtained from tables providing per unit reactances on element rat-
ings in kilovoltamperes and are converted using the following:

„ _ per-unit reactance (base kVA)

pu kVA rating

The procedure for calculating industrial system short-circuit currents consists of the follow-
ing steps:

a) Step 1 : Prepare system diagrams

b) Step 2: Collect and convert impedance data

c) Step 3: Combine impedances

d) Step 4: Calculate short-circuit current

Each step will be discussed in further detail in the following subclauses.

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4.5.1 Step 1 : Prepare system diagrams

A one-line diagram of the system should be prepared to show all sources of short-circuit cur-
rent and all significant circuit elements. Figure 4-10, used for a subsequent example, is a one-
line diagram of a hypothetical industrial system.

Impedance information may be entered on the one-line diagram after initial data collection
and after conversion. Sometimes it is desirable to prepare a separate diagram showing only
the impedances after conversion. If the original circuit is complex and several steps of simpli-
fication are required, each may be recorded on additional impedance diagrams as the calcula-
tion progresses.

The impedance diagram might show reactances only or it might show both reactances and
resistances if a vector calculation is to be made. For calculation of a system X/R ratio, as
described later for high-voltage circuit breaker duties, a resistance diagram showing only the
resistances of all circuit elements shall be prepared.

4.5.2 Step 2: Collect and convert impedance data

Impedance data, including both reactance and resistance, should be collected for important
elements and converted to per-unit on bases selected for the study. See annex 4A at the end of
this chapter for typical values.

Since resistance is not constant but varies with temperature, consideration should be given to
the choice of resistance values for study purposes.

For calculations of maximum short-circuit currents to select electric power system equip-
ment, a fully loaded industrial power system is recommended because it has the largest num-
ber of motors connected and contributing to short-circuit current. Consequently, “hot” or
rated load resistance values are usually accepted for these calculations. The collected data in
annex 4A reflect this acceptance; for example, machine X/R ratios are at rated load, overhead
line resistances are at 50 °C, and cable resistances are at 75 °C and 90 °C.

These “hot” resistance values are also acceptable as conservative impedance data for load
flows and similar calculations where probable maximum voltage drops and losses are desired
results. This multiple usage provides a simplification of data preparation.

There is a concern that system operations at less than full load could reduce equipment and
component temperatures, thus lowering resistances and increasing maximum short-circuit
currents calculated using impedances. This does not happen in most cases for industrial sys-
tems because the reduction in connected motors, at the reduced load and thus in motor contri-
bution to the calculated short-circuit current, more than offsets the possible increase due to
reduced resistance and increased X/R ratio.

In addition, for industrial systems where relatively high values of short-circuit current are
expected, the short-circuit point reactance is generally much larger than the resistance and.

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127

Figure 4-10— One-line diagram of industrial system example

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due to the quadrature relationship of X and R, a possibly justifiable reduction in “hot” resis-
tance values usually makes no significant difference in fault point impedance.

The effect of reduced resistance at reduced temperature should be examined in particular
cases not covered by the general procedures of this chapter. For example, the calculation of
the short-circuit current of an individual generator just being energized, before it takes load,
should use ambient temperature resistance and X/R ratios for a conservative result. For indus-
trial plant office buildings, and for other facilities with largely non-motor loads, full load
might be applied without delay at start-up and calculations should account for pre-start-up
temperatures of components and their resistances. For a low-voltage short circuit at the end of
a feeder from a substation to a non-motor load, where the resistance of the feeder circuit is
significant in determining short-circuit current magnitude, it may be appropriate to assume a
no-load feeder conductor temperature and resistance to calculate a maximum current.

4.5.3 Step 3: Combine impedances

The third step is to combine reactances or vector impedances, and resistances where applica-
ble, to the point of fault into a single equivalent impedance, reactance, or resistance. The
equivalent impedance of separate impedances in series is the sum of the separate impedances.
The equivalent impedance of separate impedances in parallel is the reciprocal of the sum of
the reciprocals of the separate impedances. Three impedances forming a wye or delta config-
uration can be converted by the following formulas for further reduction (figure 4-11).

a) Wye to delta [figure 4-1 1(a)]:

. b ■ c ,

A = + b + c

n a • c

B — + ci + c

„ a ■ b ,

C — + q, 4 - b

b) Delta to wye [figure 4-1 1(b)]:

= BC
° A+B+C

A- C

? ~ A + B + C
A- B

C ~ A+B+C

4.5.4 Step 4: Calculate short-circuit current

The final step is to calculate the short-circuit current. Calculation details are influenced by the
system nominal voltage or voltages and the results desired.

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a) Wye to delta

It should be noted that nominal system voltages according to ANSI C84. 1-1989 are as
follows:

a) Low voltage— less than 1000 V

b) Medium voltage— equal to or greater than 1000 V and less than 100000 V

c) High voltage— equal to or greater than 100000 V and equal to or less than 230000 V

IEEE high-voltage circuit breaker standards, IEEE Std C37.010-1979 and IEEE Std C37.5-
1979, define high-voltage circuit breakers as those rated above 1000 V, so these standards
cover calculating short-circuit currents for circuit breaker applications in both medium- and
high-voltage systems. The results of these calculations are also usable when applying
medium- and high-voltage fuses.

This chapter examines three basic networks of selected impedances used for the results most
commonly desired:

a) First-cycle duties for fuses and circuit breakers

b) Contact-parting (interrupting) duties for medium- and high-voltage circuit breakers

c) Short-circuit currents at operating times for time-delayed relaying devices

The three networks have the same basic elements except for the impedances of rotating
machines. These depend on the purpose of the study. Where interrupting equipment applica-

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tions are the purpose of the calculation, the differing impedances are based on standard appli-
cation guides.

4.5.4. 1 First-cycle duties for fuses and circuit breakers

For calculations of short-circuit duties to be compared with the interrupting ratings of low-,
medium-, or high-voltage fuses or of only low-voltage circuit breakers (according to ANSI
C97. 1-1972, IEEE Std" C37.13-1981, IEEE Std C37.41-1981, NEMA AB 1-1975, and
NEMA SG 3-1981), unmodified or modified subtransient impedances are used to represent
all rotating machines in the equivalent network.

Low-voltage duties. The standards for interrupting equipment allow a modified subtransient
reactance for a group of low-voltage induction and synchronous motors fed from a low-
voltage substation. If the total of motor horsepower ratings at 480 or 600 V is approximately
equal to (or less than) the transformer self-cooled rating in kilovoltamperes, a reactance of
0.25 per unit based on the transformer self-cooled rating may be used as a single impedance
to represent the group of motors.

Medium- and high-voltage short-circuit duties calculated with these impedances are used
when applying medium- or high-voltage fuses and when finding medium- or high-voltage
system available short-circuit duties for use as factors in subsequent low-voltage calculations.

Medium- and high-voltage duties. For calculations of short-circuit duties to be compared
with only medium- or high-voltage circuit breaker closing and latching capabilities according
to IEEE Std C37.010-1979 (post-1964 rating basis) or momentary ratings according to the
withdrawn standard, IEEE Std C37. 5-1979 (pre-1964 rating basis), multiplying factors
shown in the first cycle column of Table 4- 1 are applied to rotating machine reactances (or
impedances). For motors, this approximates the ac decay during the first cycle of motor short-
circuit current contribution.

The preceding description indicates that the different treatments of induction motors might
uneconomically necessitate two first-cycle calculations for comprehensive industrial system
short-circuit studies covering both low and high (including medium) voltages, if procedures
of applicable standards are followed without interpretation. The high- (including medium-)
voltage circuit breaker application procedure described in IEEE Std C37.010-1979 and IEEE
Std C37.5-1979 defines three induction motor size groups, recommends omitting the group of
motors each less than 50 hp, and applies multiplying factors of 1.2 or 1.0 to subtransient
impedances of motors in the groups of larger and larger sizes. The low-voltage circuit breaker
application guide, IEEE Std C37.13-1981, recommends subtransient impedances (typically
0.16 to 0.20 per unit) for all motors and allows estimates of typical symmetrical first-cycle
contributions from connected low-voltage motors to substation bus short circuits at 4 times
rated current (the equivalent of 0.25 per unit impedance).

The 4 times rated current short-circuit contribution estimate is determined approximately in
the low-voltage circuit breaker application guide, IEEE Std C37. 13-1981, by assuming a
typical connected group having 75% induction motors at 3.6 times rated current and 25%
synchronous motors at 4.8 times rated. Other typical group assumptions could be made; for

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Table 4-1 — Rotating-machine reactance (or impedance) multipliers

Type of rotating machine

First-cycle

network

Interrupting

network

All turbine generators; all hydrogenerators with
amortisseur windings; all condensers

1.0 X/'

Hydrogenerators without amortisseur windings

0-75 X/

0.75 X/

All synchronous motors

1.0 X/'

1.5 X/'

Induction motors

Above 1000 hp at 1800 r/min or less

1.0 X/'

1.5 X/'

Above 250 hp at 3600 r/min

1.0 X/'

1.5 X/'

All others, 50 hp and above

1.2 X/'

3-0 X/

All smaller than 50 hp

neglect

Source: Based on IEEE Std C37.010-1979 and TF. F.F. Std C37.5-1979.

example, many groups now have larger size low-voltage induction motors instead of synchro-
nous motors, but these larger motors also have higher and longer lasting short-circuit current
contributions. Accordingly, a 4 times rated current approximation continues to be accepted
practice when the load is all induction motors of unspecified sizes.

Combination first-cycle network. To simplify comprehensive industrial system calculations, a
single combination first-cycle network is recommended to replace the two different networks
just described. It is based on the following interpretation of IEEE Std C37. 010-1979, IEEE
Std C37. 5-1979, and IEEE Std C37. 13-1990. Because the initial symmetrical rms magnitude
of the current contributed to a terminal short circuit might be 6 times rated for a typical induc-
tion motor, using a 4.8 times rated current first-cycle estimate for the large low-voltage
induction motors (described as all others, 50 hp and above in Table 4-1) is effectively the
same as multiplying subtransient impedance by approximately 1.2. For this motor group,
there is reasonable correspondence of low- and high-voltage procedures. For smaller induc-
tion motors ( all smaller than 50 hp in Table 4-1) a conservative estimate is the 3.6 times rated
current (equivalent of 0.28 per unit impedance) first-cycle assumption of low-voltage stan-
dards, and this is effectively the same as multiplying subtransient impedance by 1.67.

With this interpretation as a basis, the following induction motor treatment is recommended
to obtain a single-combination first-cycle short-circuit calculation for multivoltage industrial
systems:

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a) Include connected motors, each less than 50 hp, using either a 1.67 multiplying factor
for subtransient impedances, if available, or an estimated first-cycle impedance of
0.28 based on motor rating.

b) Include larger motors using the impedance multiplying factors of Table 4- 1 . Most
low-voltage motors 50 hp and larger are in the 1.2 times subtransient reactance
group. An appropriate estimate for this group is first-cycle impedance of 0.20 per unit
based on motor rating.

The last two lines of Table 4- 1 are replaced by Table 4-2 for the recommended combination
network.

The single-combination first-cycle network adds conservatism to both low- and high-voltage
standard calculations. It increases calculated first-cycle short-circuit currents at high voltage
by the contributions from small induction motors and at low voltage, when many motors are
50 hp or larger, by the increased contribution of larger low- voltage induction motors.

Table 4-2— Combined network rotating machine
reactance (or impedance) multipliers
(changes to table 4-1 for comprehensive multivoltage system calculations)

Type of rotating machine

First-cycle

network

Interrupting

network

Induction motors

All others, 50 hp and above

1-2 V*

3.0 X/t

All smaller than 50 hp

1-67 X d " *

neglect

*Or estimate the first-cycle network X = 0.20 per unit based on motor rating.

' Or estimate the interrupting network X = 0.50 per unit based on motor rating.
*Or estimate the first-cycle network X = 0.28 per unit based on motor rating.

Once the first-cycle network has been established and its impedances are converted and
reduced to a single equivalent per-unit impedance Z pu (or reactance X pu ) for each fault point
of interest, the symmetrical short-circuit current duty is calculated by dividing the per-unit
prefault operating voltage /s pu by Z pu (or X pu ) and multiplying by base current:

I = — E . /

sc sym y base
^pu

where 7 SC sym is a three-phase symmetrical first cycle bolted short-circuit (zero impedance at
the short-circuit point) rms current.

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The calculated short-circuit current results for low-voltage buses are now directly applicable
for comparison with low-voltage circuit breakers, fuses, and other equipment short-circuit
ratings or capabilities expressed as symmetrical rms currents. For low-voltage circuit
breakers, ratings incorporate an asymmetrical capability as necessary for a circuit X/R ratio of
6.6 or less (short-circuit power factor of 15% or greater). A typical system served by a trans-
former rated 1000 or 1500 kVA will usually have a short-circuit X/R ratio within these limits.
For larger or multitransformer systems, it is advisable to check the X/R ratio; if it is greater
than 6.6, the circuit breaker or fuse application should be based on asymmetrical current
limitations (see IEEE Std C37.13-1990).

When the equipment rating or capability is expressed as a first-cycle total (asymmetrical) rms
current, or first-cycle crest current, the calculated symmetrical short-circuit current duty is
multiplied by a corresponding multiplying factor found in the applicable standard to obtain
the appropriate first-cycle total (asymmetrical) rms current duty, or first-cycle crest current
duty, for comparison.

Closing and latching capabilities of high-voltage circuit breakers preferred before 1 987 (or
momentary ratings of older units) are total (asymmetrical) rms currents. The appropriate cal-
culated first-cycle duty for comparison is obtained using the 1.6 multiplier specified in IEEE
Std C37.010-1979 and IEEE Std C37. 5-1979 and the fault point reactance X pu (or impedance
Z pu ) obtained by network reduction:

1 6 • -EH • J

10 v 1 base

A pu

where 7 SC tot is the maximum total (asymmetrical) rms magnitude of the current with highest
asymmetry during the first cycle of a three-phase bolted (zero impedance at the short-circuit
point) short circuit.

Closing and latching capabilities of high-voltage circuit breakers preferred after 1987 are
crest currents. The appropriate calculated first-cycle duty for comparison is obtained using
the 2.7 multiplier specified in IEEE Std C37. 010-1979 and the fault point reactance A pu (or
impedance Z pu obtained by network reduction:

J =97- pu • J

sc crest V base

A pu

where I sc crest is the maximum possible crest for one of the currents during the first cycle of a
three-phase bolted (zero impedance at the short-circuit point) short circuit.

4. 5. 4. 2 Contact-parting (interrupting) duties for high-voltage (above 1 kV,
including medium-voltage) circuit breakers

First considered are the duties for comparison with interrupting ratings of older circuit
breakers rated on the pre-1964 total rms current rating basis. The procedures of IEEE
Std C37.5- 1979 apply.

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The multiplying factors for reactances of rotating machines in the network are obtained from
the “Interrupting network” columns of tables 4-1 and 4-2.

For these interrupting duty calculations, the resistance ( R ) network is also necessary. In the
resistance network, each rotating machine resistance value must be multiplied by the factor
from table 4-1 that was used to modify the corresponding rotating machine reactance.

At the point of short circuit, reduce the reactance network to a single equivalent reactance X pu
and reduce the resistance network to a single equivalent resistance /? pu . Determine the X/R
ratio by dividing A pu by /? pu ; determine £ pu , the prefault operating voltage; and determine
E/X by dividing £ pu by X pu .

Select the multiplying factor for E/X correction from the curves of figures 4-12 and 4-13. To
use the curves, it is necessary to know the circuit breaker contact parting time as well as the
proximity of generators to the point of short circuit (local or remote). Local generator multi-
plying factors apply only when generators that are predominant contributors to short-circuit
currents are located in close electrical proximity to the fault as defined in the caption of figure
4-12 (and figure 4-14).

Minimum contact parting times are usually used and are defined in table 4-3.

Multiply £p U /X pll by the multiplying factor and the base current:

multiplying factor • — — • I

^pu

base

This is the three-phase, contact-parting time, bolted (zero impedance at the short-circuit
point), calculated, total (asymmetrical), rms short-circuit-current interrupting duty to be
compared with the circuit-breaker interrupting capability. For older circuit breakers with total
three-phase interrupting ratings in MVA. the short-circuit-current capability in kA is found by
dividing the rating in MVA by J3 and by the operating voltage in kV when the voltage is
between the rated maximum and minimum limits.

asymmetrical interrupting capability in kA

interrupting rating in MVA
J?> • operating voltage in kV

The minimum-limit voltage calculation applies for lower voltages.

Next, consider the duties for comparison with the short-circuit (interrupting) capabilities of
circuit breakers rated on the post- 1964 symmetrical rms current basis. Procedures specified in
IEEE Std C37. 010-1979 apply to calculating duties for these circuit breakers.

E/X and the X/R ratio for a given fault point are as already calculated.

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MULTIPLYING FACTORS

NOTE: Fed predominantly from generators
through no more than one transformation or
with external reactance in series that is less than
1.5 times generator subtransient reactance
(IEEE Std C37.5-1979).

MULTIPLYING FACTORS

NOTE: Fed predominantly through two or more
transformations or with external reactance in
series equal to or above 1.5 times generator sub-
transient reactance (IEEE Std C37. 5-1979).

Figure 4-12— Multiplying factors
(total current rating basis)
for three-phase faults
(local)

Figure 4-13— Multiplying factors
(total current rating basis)
for three-phase and
line-to-ground faults
(remote)

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/ j

/ j “/

/#/_

t$i

3 CYCL
CIRCUI
BREAK
1

1.0 l.l 1.2 1.3 1.4 1.0 l.l 1.2 1.3 1.4 1.0 l.l 1.2 1.3 1.0 l.l 1.2 1.3

MULTIPLYING FACTORS

NOTE: Through no more than one transformation or with external reactance in series that is less than
1.5 times generator subtransient reactance (IEEE Std C37.010-1979).

Figure 4-14— Multiplying factors for three-phase faults
fed predominantly from generators (local)

Table 4-3— Definition of minimum contact-parting time
for ac high-voltage circuit breakers

Rated interrupting time,
cycles at 60 Hz

Minimum contact-parting time,
cycles at 60 Hz

1.5

Source: Based on IEEE Std C37.010-1979 and IEEE Std C37.5-1979.

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Select the multiplying factor for E/X correction from the curves of figures 4-14 and 4-15. To
use the curves, it is necessary to know the circuit breaker’s contact parting time as well as the
proximity of generators to the fault point (local or remote), as before.

MULTIPLYING FACTORS

NOTE: Through two or more transformations or with external reactance in series that is equal to or
above 1.5 times generator subtransient reactance (IEEE Std C37.010-1979).

Figure 4-15— Multiplying factors for three-phase and line-to-ground faults
fed predominantly from generators (remote)

Multiply E /X by the multiplying factor and the base current:

multiplying factor • • / b

The result is the calculated rms short-circuit-current interrupting duty to be compared with
the symmetrical current interrupting capability (based on rating) of a circuit breaker. (Note
that the calculated interrupting duty is truly symmetrical only if the multiplying factor for
E/X is 1.0.) The symmetrical current-interrupting capability of the circuit breaker is calcu-
lated as follows:

(rated 7 SC )( rated maximum^?)
symmetrical interrupting capability = — — —

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This calculated current shall not exceed the maximum symmetrical current-interrupting capa-
bility listed for the circuit breaker.

The calculating procedures described for first-cycle and interrupting networks are different in
several respects from procedures detailed in earlier editions of this publication that were
based on standards now superseded. The differences are intended to account more accurately
for contributions to high-voltage interrupting duty from large induction motors, for the expo-
nential decay of the dc component of short-circuit current, and for the ac decay of contribu-
tions from nearby generators.

4.5.4.3 Short-circuit currents for time-delayed relaying devices

For the application of instantaneous relays, the value of the first-cycle short-circuit current
determined by the first-cycle network should be used. For an application of time delay relays
beyond six cycles, the equivalent system network representation will include only generators
and passive elements, such as transformers and cables between the generators and the point
of short circuit. The generators are represented by transient impedance or a larger impedance
related to the magnitude of decaying generator short-circuit current at the specified calcula-
tion time. All motor contributions are omitted. Only the generators that contribute short-cir-
cuit current through the relay under consideration to the short-circuit point are considered for
the relay application. The dc component will have decayed to near zero and is not considered.
The short-circuit symmetrical rms current is £ pu /X pu , where X pu is derived from the equiva-
lent reactance network consisting of generators and passive equipment (cables, transformers,
etc.) in the short-circuit current paths protected by the relays.

4.6 Example of short-circuit current calculation for a power
system with several voltage levels

4.6.1 General discussion

The three-phase 60 FIz power system used for this example is shown in figure 4-10. For pur-
poses of the example, buses are numbered 1 through 4 with numbers shown in triangles, and
rotating machine sources of short-circuit currents are numbered SI through S10 with num-
bers shown in squares. Groups of similar rotating machines are treated as single sources, each
with a rating equal to the sum of the ratings in the group and the characteristics of the typical
machine in the group.

The purpose of the example is to calculate short-circuit duties for comparison with ratings or
capabilities of circuit breakers applied at buses 1, 2, and 3. Separate, three-phase, bolted,
short circuits are assumed at Fj, F2, and F3, one at a time. When Fj is the short circuit where
current is being calculated, bus 1 is called the fault bus.

All fault buses are at primary distribution voltages of 13.8 or 4.16 kV. Interrupting-duty cal-
culations for their circuit breakers are based on IEEE Std C37.010-1979 and IEEE Std C37.5-
1979, which cover applications of high-voltage circuit breakers (over 1000 V, including
medium voltage). First-cycle duties are calculated with the previously described single-com-

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bination network also satisfying requirements for low- voltage circuit breaker applications in
IEEE Std C37. 13-1981 and for low- and high-voltage fuses.

Note that the connected motor load assumed for the low-voltage unit substations of this
example is lower than that observed for many actual substations. Experience has shown that
the rated kVA summation for connected motors often greatly exceeds substation transformer
kVA. This is a factor to be considered in studies intended to account for future growth.

4.6.2 Utility system data

In-plant generators operating in parallel with utility system ties are the main sources both at
bus 1 and at bus 2. The representation of remote utility generators for plant short-circuit cal-
culations is often based on the utility available short-circuit current, or short-circuit apparent
power in MVA, delivered by the utility at a specified voltage from all sources outside the
plant not including contributions from in-plant sources. This utility short-circuit contribution
should be the highest applicable magnitude, probably future rather than present for conserva-
tive equipment selection, and should also specify the X/R ratio. These data are converted to an
equivalent impedance. Obtaining corresponding equivalent impedance data directly from the
utility is equally useful.

4.6.3 Per-unit calculations and base quantities

This example uses per-unit quantities for calculations. The base for all per-unit power quanti-
ties throughout the system is 10 MVA (any other value could have been selected). Voltage
bases are different for different system voltage levels, but it is necessary for all of them to be
related by the turns ratios of interconnecting transformers, as specified in kV at each num-
bered bus in figure 4-10. Any actual quantity is the per-unit magnitude of that quantity multi-
plied by the applicable base. For example, 1.1 per-unit voltage at bus 1 is actually 1.1 times
the 13.8 kV base voltage at bus 1 = 15.18 kV. Per-unit system bases and actual quantities have
identical physical relationships. For example, in three-phase systems the relationship shown
in the following equation applies both to actual quantities and to bases of per-unit quantities:

total MVA = J3(E L _ L in kV)(/ line in kA)

Other useful base quantities for this example, derived using the 10 MVA base and the base
voltages of figure 4-10 in the equations of 4.5, are listed as follows:

Base line-to-line voltage E L . L

13.8 kV

4.16 kV

Base line current (kA)

0.4184

1.388

Base line-to-neutral impedance (Q)

19.04

1.73

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This example calculates at each fault point a balanced per-unit three-phase short-circuit cur-
rent duty using one of three identical per-unit line-to-neutral positive-sequence circuits, ener-
gized by per-unit line-to-neutral voltage. Only line-to-line base voltages are listed. For
balanced three-phase circuits, line-to-line voltages in per unit of these bases are identical to
line-to-neutral voltages in per unit of their corresponding line-to-neutral base voltages.

4.6.4 Impedances represented by reactances

The usual calculation of short-circuit duties at voltages over 1000 V involves circuits in
which resistance is small with respect to reactance, so manual computations are simplified by
omitting resistances from the circuit. The slight error introduced makes the solution conser-
vative. This example employs this simplification by using only the reactances of elements
when finding the magnitudes of short-circuit duties. However, element resistance data are
necessary to determine X/R ratios as described later in this example.

4.6.5 Equivalent circuit variations based on time and standards

Calculations of high-voltage circuit breaker short-circuit current duties may make use of sev-
eral equivalent circuits for the power system, depending on the time after short-circuit incep-
tion when duties are calculated and on the procedure described in the standard used as a
basis.

The circuit used for calculating first-cycle short-circuit current duties uses subtransient reac-
tance, sometimes modified as shown in tables 4-1 and 4-2, for all rotating machine sources of
short-circuit current. Synchronous machines and large induction motors (over 250 hp at
3600 r/min or 1000 hp at 0-1800 r/min) are represented with unmodified subtransient reac-
tance. Medium induction motors (all other induction motors 50 hp and above) have subtran-
sient reactance multiplied by 1.2 (or first-cycle X is estimated at 0.20 per unit). Small
induction motors (less than 50 hp each) have subtransient reactance multiplied by 1.67 (or
first-cycle X is estimated at 0.28 per unit).

The circuit used for calculating short-circuit (interrupting) duties, at circuit-breaker mini-
mum-contact parting times of 1.5 to 4 cycles after the short-circuit starts, retains synchronous
generator subtransient reactance unchanged. It also represents synchronous motors and large
induction motors with subtransient reactance multiplied by 1.5, as well as medium induction
motors with subtransient reactance multiplied by 3.0 (or interrupting X is estimated at 0.50
per unit); it neglects induction motors with less than 50 hp.

Passive element reactances are the same in all equivalent circuits.

Resistances are necessary to find fault point X/R ratios used in short-circuit (interrupting)
duty calculations based on IEEE Std C37.010-1979 and IEEE Std C37.5-1979. The fault
point X/R ratio is the fault point X divided by the fault point R. A fault point X is found by
reducing the reactance circuit described in preceding paragraphs to a single equivalent X at
the fault point. A fault point R is found by reducing a related resistance-only circuit. This is
derived from the reactance circuit by substituting the resistance in place of the reactance of
each element, obtaining the resistance value by dividing the element reactance by the element

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X/R ratio. For motors whose subtransient reactance is increased by a multiplying factor, the
same factor must be applied to the resistance in order to preserve the X/R ratio for the motor.

The X/R data for power system elements of this example, shown in figure 4-10, are medium
typical data obtained in most cases from tables and graphs that are included in the applicable
standards and are reproduced in annex 4A at the end of this chapter.

The approximately 30-cycle network often is a minimum source representation intended to
investigate whether minimum short-circuit currents are sufficient to operate current actuated
relays. Minimum source circuits might apply at night or when production lines are down for
any reason. Some of the source circuit breakers may be open and all motor circuits may be
off. In-plant generators are represented with transient reactance or a larger reactance related
to the magnitude of decaying generator short-circuit current at the desired calculation time,
for this example assumed at 1.5 times subtransient reactance in the absence of better
information.

4.6.6 Impedance data and conversions to per unit

Reactances of passive elements, obtained from figure 4-10, are listed in table 4-4, along with
the conversion of each reactance to per unit on the 10 MVA base.

Table 4-4— Passive element reactances in per unit, 10 MVA base

Transformer Tj,

X = 0.07 (10/20) = 0.035 per unit

Transformer 73,

X = 0.055 (10/5) = 0.110 per unit

Transformer 7j,

X = 0.065 (10/5) = 0.130 per unit

Transformer r 4 .

X = 0.055 (10/5) = 0.110 per unit

Transformer T ' 5 ,

X = 0.055 (10/7.5) = 0.0734 per unit

Transformer 7" 6 ,

X = 0.055 (10/1.5) = 0.367 per unit

Reactor Xj,

X = 0.08 (10/7.5) = 0.107 per unit

Cable Cj, from tables 4A-3 and 4A-6 for 250 kcmil at 1 in spacing,

X = 0.0922-0.0571 = 0.0351 Q/1000 ft

(There are no reactance corrections as this is three-conductor cable in nonmagnetic duct.)

For 3500 ft of cable, the conversion to per unit on a 10 MVA 13.8 kV base is

X= (3500/1000) (0.0351/19.04) =0.0064 per unit

Cable C 2 , 300 kcmil at 1 in spacing,

X = 0.0902-0.0571 = 0.0331 Q/1000 ft

For 2500 ft of two cables in parallel at 4. 16 kV,

X = (2500/1000) (1/2) (0.0331/1.73) = 0.0239 per unit

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Most of the data given in figure 4-10 are per unit, based on the equipment nameplate rating.
Any original percent impedance data is divided by 100 to obtain a per-unit impedance for fig-
ure 4-10. Conversions are changes of MVA base: multiplication by the ratio of the new MVA
base (10 MVA for the example) to the old MVA base (rated MVA). When the equipment’s
rated voltage is not the same as the base voltage, it is also necessary to make voltage base
conversions using the square of the ratio of rated voltage to example base voltage as the mul-
tiplier (see 4.5). This is not illustrated in this example.

Physical descriptions of cables are used to establish their reactances in ohms based on data in
tables 4A-3 and 4A-6. Dividing an impedance in ohms by the base impedance in ohms con-
verts it to per unit.

4.6.7 Subtransient reactances of rotating machines, and reactances for the cir-
cuit to calculate first-cycle short-circuit current duties

Subtransient reactances of rotating machine sources of short-circuit current modified for the
combination first-cycle network based on interpretation of reference low- and high-voltage
standards -IEEE Std C37.010-1979, IEEE Std C37.5-1979, and IEEE Std C37. 13-1990-
are listed in table 4-5 together with conversions to per unit on the study base.

Table 4-5— Subtransient reactances of rotating machines, modified for
first-cycle (momentary) duty calculations in per unit, 10 MVA base

69 kV system, X = 1.0 (10/1000) = 0.01 per unit
Generator 1, X d "= 0.09 (10/25) = 0.036 per unit

46 kV system, X = 1.0 (10/800) = 0.0125 per unit
Generator 2, X d "= 0.09 (10/5) = 0.18 per unit

Large synchronous motor Mj, using the assumption that the horsepower rating of an 0.8 power factor
machine is its kVA rating,

X d "= 0.20 (10/6) = 0.333 per unit, each motor

Large induction motor M 2 , using the assumption that hp = kVA,
X /= 0.17 (10/1.75) = 0.971 per unit

Low- voltage motor group, 0.4 MVA, from 50 to 150 hp,

first-cycle X = 1 .2 X d = 0.20 (10/0.4) = 5.0 per unit

Low- voltage motor group, 1.12 MVA, less than 50 hp each,

first-cycle X = 1.67 X d " = 0.28 (10/1.12) = 2.5 per unit

The reactance representing the rotating machines of a utility system is found by observing
that the available short-circuit apparent power (MVA) is 1.0 per unit of a base equal to itself,
and that 1.0 per-unit short-circuit apparent power (MVA) corresponds to 1.0 per-unit reac-
tance (V) at 1.0 per-unit voltage (V), then converting this reactance to the study base.

The circuit development and impedance simplifications are described subsequently.

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4.6.8 Reactances and resistances for the circuit to calculate short-circuit
(interrupting) current duties

Reactances, and resistances derived from them as described previously, are detailed in table
4-6.

Table 4-6— X/R ratios and resistances for ac high-voltage circuit breaker
contact-parting time (interrupting) short-circuit duties

Transformer 7),

X/R = 21,

R = 0.035/21 = 0.001 667 per unit

Transformer 73,

X/R =16,

R = 0.1 10/16 = 0.006 88 per unit

Transformer 7^,

X/R = 1 6,

R = 0.130/16 = 0.008 12 per unit

Transformer T 4 ,

X/R =12,

R = 0.11/12 = 0.009 16 per unit

Transformer 73,

X/R= 14,

R = 0.0734/14 = 0.005 24 per unit

Transformer T 6 ,

X/R = 10,

R = 0.0367/10 = 0.003 67 per unit

Reactor Xj,

X/R = 50,

R = 0.107/50 = 0.002 14 per unit

Cable Ci, ac resistance at 50 °C from table 4A-3 is 0.0487 Q/1000 ft, correction for 75 °C = 1.087

For 3500 ft of cable converted to per unit on a 10 MVA 13.8 kV base,

R = (3500/1000) (1.087) (0.0487/19.04) = 0.009 72 per unit

Cable C 2 , ac resistance from table 4A-3 is 0.0407 Q/1000 ft

For 2500 ft of two cables in parallel on a 10 MVA 4. 16 kV base at 75 °C,

R = (2500/1000) (1.087/2) (0.0407/1.73) = 0.0320 per unit

69 kV system,
Generator 1,

X/R = 22,
X/R = 45,

R = 0.01/22 = 0.000 445 per unit

R = 0.036/45 = 0.0008 per unit

46 kV system,
Generator 2,

X/R = 9,
X/R = 29,

R = 0.0125/9 = 0.001 389 per unit

R = 0.18/29 = 0.0062 per unit

Large synchronous motor Mj, using X = 1.5 X d " = 1.5 (0.333) = 0.5 per unit, X/R = 30.

R = 0.5/30 = 0.016 67 per unit

Large induction motor M 2 , using X = 1.5 X J' = 1.5 (0.97 1) = 1 .457 per unit, X/R = 30,

R = 1 .457/30 = 0.048 57 per unit

Low-voltage motor group 50-
R= 12.5/9= 1.389 per unit

150 hp, using A = 3.0 X / = (3/1.2) (5.0) = 12.5 per unit, X/R = 9,

Low-voltage motor group below 50 hp is omitted

NOTE — See tables 4-4 and 4-5 for reactances of passive elements, utility systems, and generators.

4.6.9 Reactances for the circuit to calculate approximately 30-cycle minimum
short-circuit currents

Minimum generation for this problem (defined by system operators) occurs with Generator 1
down, the 46 kV utility system connection open, and all motors disconnected. Reactance
details are given in table 4-7.

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Table 4-7— Reactances for approximately 30-cycle short-circuit currents

Utility system Sj reactance is unchanged

Generator 2, S 4 is represented with reactance larger than subtransient,
assumed at 1.5 X d " = 1.5 • 0.18 = 0.27 per unit

All other sources, St, S 3 , S 5 -S 10 , are disconnected

4.6.10 Circuit and calculation of first-cycle short-circuit current duties

The circuit used for calculating the symmetrical alternating currents of the first-cycle short-
circuit duties based on a combination of current circuit breaker and fuse standards is shown in
figure 4-16(a). Source circuits S 5 through S 10 have been simplified using the series and paral-
lel combinations indicated in table 4-8, based on the per-unit element impedances obtained
directly from table 4-4 and table 4-5. The identities of buses and sources are retained in figure
4- 16(a), even after the individual element impedances from figure 4-10 lose identification
when reactances are combined.

Table 4-8— Reactances for figure 4-1 6(a)

S 5 to bus 1, two circuits in parallel, each with M| motor X d " and T 5 transformer A,
X d " = (1/2) (0.3333 + 0.0734) = 0.2034 per unit

Sg to bus 1 (after combining all the motors of one substation for an equivalent low- voltage motor X d "
= 2.5 (5)/(2.5 + 5) = 1.667, four circuits in parallel, each with an equivalent motor X d " in series
with a Tg transformer,

X d " = (1/4) (1.667 + 0.367) = (1/4) (2.034) = 0.5085 per unit

S 7 to bus 4, two Mi induction motors,

X d " = (1/2) (0.971) = 0.4855 per unit

Sg to bus 2, three circuits, each as for the Sg to bus 1 calculation,
X d " = (1/3) (2.034) = 0.678 per unit

S 9 to bus 3, two M-, induction motors,

X d " = (1/2) (0.971) = 0.4855 per unit

Sjo to bus 3, two circuits, each as for the Sg to bus 1 calculation,
X d " = (1/2) (2.034) = 1.017 per unit

The connection of an ac source, the voltage magnitude of which is the prefault voltage at the
fault bus, between the dotted common connection and the fault at the fault bus causes the flow
of per-unit alternating short-circuit current that is being calculated.

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The reactances of figure 4- 16(a) are further simplified as shown in Fig 4- 16(b), without losing
track of the three fault locations. The reactance simplifications are summarized in table 4-9.
The table contains columns of reactances and reciprocals. Arrows are used to indicate the cal-
culation of a reciprocal. Sums of reciprocals are used to combine reactances in parallel. A
dashed line in the reactance column indicates that reactances above the line have been com-
bined in parallel.

SI S2 S3 S4

SI, 2, 5, 6 S3, 4, 7, 8

(b) Simplified reactance diagram

Figure 4-16— Circuits of power system reactances for calculation of
first-cycle (momentary) short-circuit current duties for
fuses and low-voltage circuit breakers

The final simplification of reactances to obtain one fault point X for each fault location is
detailed in table 4-10. The results for the specified fault buses are the last entries in the reac-
tance columns.

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Table 4-9— Reactance combinations for figure 4-1 6(a)

Si,

S 2 ,S s ,

S 6

l/X

0.045

22.22

0.036

—

27.78

0.2034

— >

4.91

0.5085

1.97

0.0176

56.88

s 3 ,s 4 ,s 7 ,s 8

X l/X

0.1425

7.02

0.29

-»

3.45

0.5094

1.96

0.678

1.47

0.0719

13.90

s 9 , s 10

X l/X

0.4855 -» 2.060

1.017 -» 0.983

0.3286 «- 3.043

Table 4-10— Reactance combinations for fault-point X
at each fault bus of figure 4-1 6(b)

Fault at Fj

X l/X

0.3286

0.107

0.4356

— >

2.30

0.0719

-*■

13.90

0.0617

«-

16.20

0.1164

0.1781

5.62

0.0176

—

56.82

0.016

62.44

Fault at Fi

X ' l/X

0.0176

0.1164

0.1340

0.107

7.46

0.3286

0.4356

2.30

0.0719

13.90

0.0423

23.66

Fault at F

l/X

0.1340

7.46

0.0719

— >

13.90

0.0468

21.36

0.107

0.1538

6.502

0.3286

3.043

0.1048

9.545

Alternating short-circuit currents are calculated from the circuit reactance reductions X with a
prefault voltage £ of 1.0 per unit, and alternating rms current is, of course, E/X per unit. Mul-
tiplying by base current converts to real units. The resulting symmetrical (alternating only)
first-cycle short-circuit rms currents are as follows:

at F 1; 7 sym = (1.0/0.016) (0.4184) = 26.15 kA
at F 2 , 7 sym = (1.0/0.0423) (1.388) = 32.81 kA
at F 3 , 7 sym = (1.0/0.1048) (1.388) = 13.25 kA

Note that these currents may be useful as primary available symmetrical short-circuit current
data for calculations of short-circuit duties at low-voltage buses of future unit substations
connected to these medium-voltage buses.

Total (asymmetrical) rms short-circuit current duties for comparison with ac high-voltage
(over 1000 V, including medium- voltage) circuit breaker closing and latching capabilities
preferred before 1987 (or momentary ratings for the pre-1964 rating basis) are found using a

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1.6 multiplying factor according to IEEE Std C37. 010-1979 and IEEE Std C37. 5-1979.
These first-cycle short-circuit total (asymmetrical) rms currents are as follows:

at F b 7 tot = 1.6 (26.15) = 41.8 kA
at F 2 , 7 tot = 1.6 (32.81) = 52.5 kA
at F 3 , 7 tot = 1.6 (13.25) = 21.2 kA

Crest short-circuit current duties for comparison with ac high-voltage (over 1000 V, including
medium- voltage) circuit breaker closing and latching capabilities preferred in 1987 and after
are found using a 2.7 multiplying factor according to IEEE Std C37.010-1979. These first-
cycle short-circuit crest currents are as follows:

at Fj, 7 crest = 2.7(26.15) = 70.6 kA
at F 2 , 7 crest = 2.7(32.81) = 88.6 kA
at F 3 , 7 crest = 2.7(13.25) = 35.8 kA

Asymmetrical short-circuit duties are necessary for comparison with total rms current ratings
of ac high-voltage (and medium-voltage) fuses, such as those in the fused motor control
equipment connected to buses 3 and 4. These are found using multiplying factors from IEEE
Std C37.41-1981. The applicable standard for the circuit of figure 4-16 suggests a general
case multiplying factor of 1.55, but a special case multiplier of 1.2 may be substituted if the
voltage is less than 15 kV and if the X/R ratio is less than 4. The circuit of this example will
not have X/R ratios as low as 4. The first-cycle short-circuit asymmetrical (total) rms currents
for fuse applications are as follows:

at Fj, 7 tot = 1.55(26.15) = 40.73 kA
at F 2 , 7 tot = 1.55(32.81) = 50.86 kA
at F 3 , 7 tot = 1.55(13.25) = 20.54 kA

4.6.11 Circuit and calculation of contact parting time (interrupting) short-cir-
cuit current duties for high-voltage circuit breakers

In addition to a circuit of power system reactances for calculating alternating currents (7 pu =
E/X), a resistance-only circuit is needed to establish fault point X/R ratios. Duties are calcu-
lated by applying multiplying factors to E/X. The multiplying factors depend on the fault-
point X/R and also on other factors defined subsequently.

The circuits used for calculating X, E/X, and fault point R are shown in figures 4-17(a) and
4-18(a), respectively. The rotating-machine reactances for the circuit of figure 4-17(a), if
changed from subtransient, are shown in table 4-6. Table 4-11 details how these changes
affect the table 4-8 simplifications of source circuits S 5 through S 10 . Table 4-11 also includes
resistance simplifications of source circuits for figure 4- 18(a).

Figures 4- 17(b) and 4- 18(b) show the last steps of reactance and resistance simplifications,
respectively, before the several fault location identities are lost. Tables 4-12 and 4-13 detail
the reactance and resistance simplifications starting from figures 4-17(a) and 4-18(a), respec-
tively. The final simplifications of reactances and resistances to obtain one fault point X and
one fault point R for each fault location are detailed in tables 4-14 and 4-15, respectively.

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SI S2 S3 S4

(b) Simplified reactance diagram

Figure 4-17— Circuits of power system reactances for calculation of
E/X and fault-point X for contact-parting-time (interrupting)
short-circuit current duties for high-voltage circuit breakers

Values of per-unit E/X for each fault bus are readily obtained from table 4-14 when E = 1.0
(as for this example); they are the final entries in the MX columns, opposite the fault point X
entries. Values converted to actual currents are as follows:

at F 1; E/X = 59.03(0.4184) = 24.70 kA
at F 2 , E/X = 20.75(1.388) = 28.80 kA
at F 3 , E/X = 7.841(1.388) = 10.88 kA

Values of X/R for each fault bus are obtained from the fault point X and R entries of tables
4-14 and 4-15 as follows:

at Fj, X/R = 0.0169/0.000537 = 31.47
at F 2 , X/R = 0.0482/0.00348 = 13.85
at F 3 , X/R = 0.1275/0.00488 = 26.13

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(a) Reactance diagram

SI, 2, 5, 6 S3, 4, 7,8

(b) Simplified reactance diagram

Figure 4-18— Circuits of power system resistance for calculation of
fault-point R for contact-parting-time (interrupting)
short-circuit current duties for high-voltage circuit breakers

The reference standards contain graphs of multiplying factors that determine calculated
short-circuit current duties when applied to E/X values. The proper graph is selected with the
following information:

a) Three-phase or single-phase short-circuit current (three-phase for this example)

b) Rating basis of the circuit breaker being applied (present symmetrical current short-
circuit ratings or previous total current short-circuit ratings)

c) Rated interrupting time of the circuit breaker being applied

d) Fault point X/R ratio

e) Proximity of generators

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Table 4-11 — Reactances for figure 4-1 7(a) and resistances for figure 4-1 8(a)

S 5 to bus 1, two circuits in parallel, each with 1.5 X d " of synchronous Motor M| and transformer T 5 ,
X = (1/2) (0.5 + 0.0734) = 0.2867 per unit

R = (1/2) (0.016 67 + 0.005 31) = (1/2) (0.021 98) = 0.010 99 per unit

S§ to bus 1, four circuits in parallel, motor group and transformer T 6 ,

X = (1/4) (12.5 + 0.367) = (1/4) (12.867) = 3.217 per unit
R = (1/4) (1.389 + 0.0367) = (1/4) (1.4257) = 0.356 per unit

S 7 to bus 4, two motors M-,,

X = (1/2) (1.457) = 6.7285 per unit
R = (1/2) (0.048 57) = 0.024 29 per unit

Sg to bus 2, three circuits, each as for the S 6 to bus 1 calculation,

X = (1/3) (12.867) = 4.289 per unit
R = (1/3) (1.4257) = 0.475 per unit

S 9 to bus 3, two motors M->,

X = (1/2) (1.457) = 6.7285 per unit
R = (1/2) (0.048 57) = 0.024 29 per unit

Sjo to bus 3, two circuits, each as for the S 6 to bus 1 calculation,

X = (1/2) (12.867) = 6.434 per unit
R = (1/2) (1.4257) = 0.713 per unit

Table 4-12— Reactance combinations for figure 4-17(a)

s„s 2 , S 5 , S 6 S„ S 4 , S 7 , S s s 9 ,s 10

1/X

0.045

22.22

0.1425

-* 7.018

0.7285

— >

1.373

0.036

-►

27.78

0.29

-» 3.448

6.434

0.155

0.2867

3.217

3.49

0.31

0.7524

4.289

-* 1.329

-» 0.233

0.6545

1.528

0.0186

53.80

0.0831

«- 12.028

Table 4-13— Resistance combinations for figure 4-18(a)

Si, s 2 ,s,

5; S 6

1/R

S 3 ,

s 4 ,s 7 ,s 8

1/R

s 9 , s 10

1/R

0.002 122 -►

0.000 8 -*

471.3

1250.0

0.009 509
0.015 36

-» 105.2

— 65.10

0.024 29 -*

0.713 -»

41.17

1.403

0.010 99 -»

0.356 -►

90.99

2.81

0.056 29
4.475

17.77

-» 2.11

0.023 49

42.57

0.000 551 1«-

1815

0.005 26

«- 190.3

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IEEE
Std 141-1993

Table 4-14— Reactance combinations for fault-point X
at each fault bus of figure 4-1 7(b)

Fault at F

1/X

0.6545

0.107

0.7615

1.313

0.0831

12.03

0.0750

«-

13.34

0.1164

0.1914

5.225

0.0186

53.80

0.0169

«_

59.03

Fault at F

1/X

0.0186

0.1164

0.135 -*

7.407

0.7615 -*

1.313

0.0831 -*

12.03

0.0482 «-

20.75

Fault at F

1/X

0.135

7.407

0.0831

12.03

0.0514

19.44

0.107

0.1584

6.313

0.6545

1.528

0.1275

7.841

Table 4-15— Reactance combinations for fault-point R
at each fault bus of figure 4-1 8(b)

The proximity of generators determines the choice between graphs (a) for faults fed predom-
inantly from generators through not more than one transformation or with external imped-
ance in series that is less than 1.5 times generator X,/' (local in this example) and (b) for faults
fed predominantly through two or more transformers or with external impedance in series
that is equal to or exceeds 1.5 times generator X d " (remote in this example). The local and
remote multiplying factor graphs of IEEE Std C37.010-1979 and IEEE Std C37. 5-1979 are
given in figures 4-12 to 4-15. The local multiplying factors are smaller because they include
the effects of generator ac (symmetrical current) decay. Remote multiplying factors are based

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on no decay of the remote generator ac (symmetrical current) up to circuit breaker contact
parting time. Utility contributions are considered to be from remote generators in most indus-
trial system duty calculations.

For many systems having only remote sources and no in-plant generators, it is clear that the
remote multiplying factor is the only choice. For the few systems that have in-plant generator
primary power sources, both multiplying factors may be necessary, as explained subse-
quently.

In this example, short-circuit duties are calculated for (SYM) symmetrical current short-
circuit rated (present basis) circuit breakers with 5-cycle rated interrupting times (SYM 5)
and (TOT) total-current short-circuit rated (previous basis) circuit breakers with 8-cycle and
5-cycle rated interrupting times (TOT 8 and TOT 5).

Multiplying factors obtained from both the local and remote graphs of figures 4-12 to 4-15
are shown in table 4-16 for the other conditions previously established in this example.

Table 4-16— Three-phase short-circuit current multiplying factors
for E/X for example conditions

Fault

Fault-point

Circuit

Multiplying factor

location

X/R ratio

breaker type

Local

Remote

31.47

TOT 8

1.05

1.19

TOT 5

1.14

1.27

SYM 5

1.03

1.15

f 2

13.85

TOT 8

1.0"

1.0*

TOT 5

1.01

1.06

SYM 5

1.0"

1.0*

f 3

26.13

TOT 8

1.02

1.14

TOT 5

1.10

1.21

SYM 5

1.00

1.10

"IEEE Std C37.010-1979 and IEEE Std C37.5-1979 indicate that a 1.0 multiplying
factor applies without further checking when X/R = 15 or less for SYM circuit breakers
of all rated interrupting times and for TOT 8 circuit breakers.

In this example, with each of two main buses connected to both a utility (remote) source and
an in-plant generator (local for nearby faults) source, it is not immediately apparent which
multiplying factor applies. One technique that perhaps provides an extra margin of conserva-
tism is to use only the larger remote multiplying factors as described in the next paragraphs.
An alternative and also conservative procedure that interpolates between multiplying factors
requires additional calculations (see 4.6.13).

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The calculated interrupting duty short-circuit rms currents for three-phase faults at bus 1,
using remote multiplying factors, are as follows:

for SYM 5 circuit breakers, 1.15(24.70) = 28.41 kA-S
for TOT 8 circuit breakers, 1.19(24.70) = 29.39 kA-T
for TOT 5 circuit breakers, 1.27(24.70) = 31.37 kA-T

The kA-T designation denotes an rms current duty in kiloamperes to be compared with the
total current short-circuit (interrupting) capability of a total-rated circuit breaker. This is a
total (asymmetrical) rms current duty.

The kA-S designation denotes an rms current duty in kiloamperes to be compared with the
symmetrical-current short-circuit (interrupting) capability of a symmetrical-rated circuit
breaker. This is a symmetrical rms current duty only if the multiplying factor for E/X is 1.0;
otherwise, it is neither symmetrical nor asymmetrical, but partway in between.

The F 2 fault calculation for a TOT 5 circuit breaker is not detailed in this example. SYM 5
and TOT 8 duties at bus 2 are already available, since 1.0 multiplying factors apply, as
follows:

for SYM 5 circuit breakers, 1.0(28.80) = 28.80 kA-S
for TOT 8 circuit breakers, 1.0(28.80) = 28.80 kA-T

The calculated short-circuit (interrupting) duty rms currents for three-phase faults at bus 3,
using remote multiplying factors, are as follows:

for SYM 5 circuit breakers, 1.10(10.88) = 11.97 kA-S
for TOT 8 circuit breakers, 1.14(10.88) = 12.40 kA-T
for TOT 5 circuit breakers, 1.21(10.88) = 13.16 kA-T

4.6.12 Circuit-breaker short-circuit capabilities compared with calculated
remote multiplying-factor short-circuit current duties

Short-circuit ratings, or capabilities derived from them, for circuit breakers that might be
applied in the example system are listed in table 4-17. The headings of the table also show in
parentheses the type of calculated short-circuit duties to be compared with listed equipment
capabilities or ratings. The capabilities derived from symmetrical short-circuit ratings using a
ratio of rated maximum voltage to operating voltage are computed using the example operat-
ing voltages listed in the table.

Circuit breakers for bus 1 application, both SYM 5 and TOT 8 types, having short-circuit rat-
ings or capabilities equal to or greater than the corresponding calculated duties at bus 1, are
listed in table 4-18 with the calculated duties for comparison. Circuit breakers for bus 2 and 3
applications are listed in tables 4-19 and 4-20, respectively, with short-circuit ratings or capa-
bilities and calculated duties.

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Table 4-17— AC high-voltage circuit-breaker short-circuit ratings
or capabilities, in kiloamperes

TOT 8

8-cycle total-rated circuit
breakers

SYM 5

5-cycle symmetrical-rated circuit
breakers

Circuit

breaker

nominal

size

identification

Example

maximum

system

operating

voltage

(kV)

Momentary
rating
(first-cycle
total rms
current)

Interrupting
rating
(total rms
current at
4-cycle
contact-
parting
time)

Closing

and

latching
capability
before 1987
(first-cycle
total rms
current)

Closing

and

latching
capability
1987 and
after (first-
cycle crest
current)

Short-circuit
capability
(symmetrical
rms current
at 3-cycle
contact-
parting
time)

4.16-75

4.16

10.5

10.1

4.16-250

4.16

33.2

4.16-350

4.16

48.6

132

46.9

13.8-500

13.8

19.6

13.8-750

13.8

31.5

30.4

13.8-1000

13.8

130

40.2

4.6.13 Contact parting time (interrupting) duties for high-voltage circuit
breakers using weighted interpolation between multiplying factors

For a system with several sources, including in-plant generators that might be classified local
or remote depending on fault location, logical calculations make use of both remote and local
multiplying factors in a weighting process. The weighting consists of applying the remote
multiplying factor to the part of the E/X symmetrical short-circuit current contributed by
remote sources and the local multiplying factor to the remainder of E/X. The application of
either a local or a remote multiplying factor to the motor contribution part of E/X is permitted
by IEEE Std C37.010-1979 (5.4.1, note 5 of the table). The remote sources’ part of E/X
includes the contribution of an in-plant generator if it is less than 0.4 times the generator cur-
rent to a short circuit at its terminals; any larger generator current corresponds to a reactance
in series that is less than 1.5 times generator X/ and supports the use of a local multiplier for
the generator contribution, according to IEEE Std C37. 010-1979 and IEEE Std C37. 5-1979.

Additional calculations are necessary to find the short-circuit currents contributed by each
utility and in-plant generator source to the short-circuit duties being investigated. The magni-

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Table 4-18— Calculated bus 1 short-circuit duties compared with
ratings or capabilities of ac high-voltage circuit breakers

Type of circuit breaker

TOT 8 (8-cycle
total rated)

SYM 5 (5-cycle
symmetrical
rated)

First-cycle duty, before 1987, total rms current

41.8 kA

First-cycle duty, 1987 and after, crest current

70.6 kA

Short-circuit (interrupting) duty, rms current

29.4 kA-T

28.4 kA-S

Circuit breaker nominal size

13.8-750

Momentary rms current rating, or closing and
latching rms capability, before 1987

60 kA

58 kA

Closing and latching crest capability, 1987 and after

97 kA

Interrupting rating, or short-circuit current capability

31.5 kA

30.4 kA

Table 4-19— Calculated bus 2 short-circuit duties compared with
ratings or capabilities of ac high-voltage circuit breakers

Type of circuit breaker

TOT 8 (8-cycle
total rated)

SYM 5 (5-cycle
symmetrical
rated)

First-cycle duty, before 1987, total rms current

52.5 kA

First-cycle duty, 1987 and after, crest current

88.6 kA

Short-circuit (interrupting) duty, rms current

28.8 kA-T

28.8 kA-S

Circuit breaker nominal size

4.16-250

Momentary rms current rating, or closing and latch-
ing rms capability, before 1987

60 kA

58 kA

Closing and latching crest capability, 1987 and after

97 kA

Interrupting rating, or short-circuit current capability

35 kA

33.2 kA

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Table 4-20— Calculated bus 3 short-circuit duties compared with
ratings or capabilities of ac high-voltage circuit breakers

Type of circuit breaker

TOT 8 (8-cycle
total rated)

SYM 5 (5-cycle
symmetrical
rated)

First-cycle duty, before 1987, total rms current

21.2 kA

First-cycle duty, 1987 and after, crest current

35.8 kA

Short-circuit (interrupting) duty, rms current

12.4 kA-T

12.0 kA-S

Circuit breaker nominal size

4.16-250

Momentary rms current rating, or closing and latch-
ing rms capability, before 1987

60 kA

58 kA

Closing and latching crest capability, 1987 and after

97 kA

Interrupting rating, or short-circuit current capability

35 kA

33.2 kA

tude of an in-plant generator contribution for each short circuit determines whether it is
included with utility sources in the remote part of E/X.

The additional calculation of currents in the source branches of the equivalent circuit during a
short circuit at a specified location is a multistep process not illustrated here (and greatly
facilitated by available computer programs). The results of the necessary calculations for this
example are given in table 4-21. Also shown are remote or local classifications for the in-
plant generators contributing to short circuits at Fj, F2, and F3.

The weighted interpolation has significance only for the short circuit at Fj. For the short
circuit at F2, the local and remote multiplying factors are both 1.0 (for SYM 5 and TOT 8
duties) and interpolation has no effect. For the short circuit at F 3 , since all sources including
in-plant generators are classified as remote, the remote multiplying factor applies.

For the short circuit at Fj, the remote part of E/X = 22.22 + 2.75 + 1.35 = 26.32 per unit, and
the remainder of E/X = 59.03 - 26.32 = 32.71 per unit. The calculated short-circuit interrupt-
ing-duty rms currents for three-phase short circuits at bus 1 (Fj), using weighted interpolation
of multiplying factors, are as follows:

for SYM 5 circuit breakers, 1.15 (26.32) + 1.03 (32.71) = 64.0 per unit or 64.0 (0.4184) =
26.8 kA-S

for TOT 8 circuit breakers, 1.19 (26.32) + 1.05 (32.71) = 65.67 per unit or 65.67 (0.4184) =
27.5 kA-T

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Table 4-21 —Current contributions of separate sources (generators)
to E/X symmetrical short-circuit (interrupting) duties,
with sources classified remote or local
(currents are in per unit on the 10 MVA base of this example)

Fault contributions and classifications*

Fault at Fj

Fault at F 2

Fault at F 3

Fault point E/X symmetrical short-circuit current

59.03

20.75

7.84

Sj-69 kV utility contribution

22.22

3.06

0.99

Classification

remote

S 2 -25 MVA generator contribution

27.78

3.83

1.24

Classification^

local

remote

S 3 -48 kV utility contribution

2.75

7.02

2.28

Classification

remote

S 4-5 MVA generator contribution

1.35

3.45

1.12

Classification 1 '

remote

local

remote

Utility is always remote, in-plant generator is remote if contribution is less than 0.4 E/X"
' E/X " (for three-phase short circuit at terminals) = 27.78 per unit
*E/X" (for three-phase short circuit at terminals) = 5.56 per unit

Comparison of these results with previously calculated bus 1 results, table 4-18, shows that
the previous use of only remote multiplying factors gives an extra margin of conservatism of
6 or 7% in this example.

4.6.14 Circuit and calculation of approximately 30-cycle minimum short-circuit
currents

The circuit used is shown in figure 4-19. The rotating-machine reactances are shown in table
4-7. Table 4-22 details the reactance simplifications starting from figure 4- 19(b).

A prefault voltage of 1.0 per unit is assumed, I is calculated at E/X per unit, and the conver-
sion is made to real units. There is no dc component remaining to cause asymmetry. The
resulting, symmetrical, approximately 30-cycle, short-circuit currents are as follows:

at Fj, /= (1.0/0.0413) (0.4184) = 10.14 kA
at F 2 , /= (1.0/0.1133) (1.388) = 12.25 kA
at F3 , 1 = (1.0/0.2203) (1.388) = 6.30 kA

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SI S2 S3 S4

SI, 2, 5, 6 S3, 4, 7, 8

Figure 4-19— Circuits of power system reactances for calculation of
approximately 30-cycle minimum short-circuit currents

4.7 Example of short-circuit current calculation for a low-voltage
system (under 1000 V)

As in portions of a power system with voltage over 1000 V, calculation of short-circuit cur-
rents at various locations in a low-voltage system (voltage under 1000 V) is essential for
proper application of circuit breakers, fuses, buses, and cables. All should withstand the ther-
mal and magnetic stresses imposed by the maximum possible short-circuit currents until the
currents are interrupted. In addition, circuit breakers and fuses should safely interrupt these
maximum short-circuit currents.

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Table 4-22— Reactance combinations for fault-point X
at each fault bus of figure 4-1 9(b)

Fault at Fj

Fault at F

Fault at F 3

0.38

0.045

0.1133

0.1164

0.107

0.4964

-*■ 2.0145

0.1614

6.1958

0.2203

0.045

-*• 22.2222

0.38

-»

2.6316

0.041 26

«- 24.2367

0.1133

8.8274

For the three-phase system, the three-phase short circuit will usually produce the maximum
fault current. On a balanced three-phase system, the line-to-line fault current will never
exceed 87% of the three-phase value. With a system neutral solidly grounded, the line-to-
ground fault current could exceed the three-phase short-circuit current by a small percentage;
however, this is apt to occur only when there is little or no motor load and the primary system
fault contribution is small.

The calculation of symmetrical short-circuit current duties is normally sufficient for the
application of circuit breakers and fuses under 1000 V because they have published symmet-
rical-current-interrupting ratings. The ratings are based on the first-cycle symmetrical rms
current, calculated using results at 1/2 cycle after short-circuit-current inception, and incorpo-
rate an asymmetrical capability as necessary for a circuit X/R ratio of 6.6 or less (short-circuit
power factor of 15% or greater). A typical system served by a transformer rated 1000 or
1500 kVA will usually have a short-circuit X/R ratio within these limits. For larger or multi-
transformer systems, it is advisable to check the X/R ratio; if it is greater than 6.6, the circuit
breaker or fuse application should be based on asymmetrical current limitations (see IEEE
Std C37.13-1990).

The low- voltage short-circuit current calculation procedure differs very little from that used
for finding first-cycle short-circuit duties in higher voltage systems. All connected motor rat-
ings are included as fault contributing sources, and this contribution is based on the subtran-
sient reactance of the machines. The contribution from the primary system should be
equivalent to that calculated for its first-cycle short-circuit duty. Due to the quantity and small
ratings of motors usually encountered in low-voltage systems, it is customary to use an
assumed typical value for their equivalent reactance in the low-voltage short-circuit network.
This typical reactance value is 25% (0.25 per unit) based on the individual motor rating or the
total rating of a group of motors, both in kilovoltamperes (see 4.5.4).

The example fault calculation presented here is for a 480 V three-phase system, illustrated by
the single line diagram of figure 4-20. The system data shown are typical of those required to
perform the calculations.

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Std 141-1993

CHAPTER 4

13.8 kV SYSTEM

v 3-PHASE SHORT-CIRCUIT CONTRIBUTION = 600 MVA,

I SYMMETRICAL (MOMENTARY DUTY)

X/R = I5

T,, 1000 kVA, 3-PHASE
13.8 kV-480 V
Z = 5.75%

R = 1.21%

480 V 3-PHASE SWITCHGEAR BUS

) )

\' t'

NOTE: The motor horsepower indicated at MCC 1 and 2 represents a lumped total of small induction
three-phase machines ranging in size from 10-150 hp.

Figure 4-20— Low-voltage system

Bolted three-phase short circuits Fj and F 2 are assumed at each of the bus locations, and zero
impedance (bolted) line-to-line short circuits F 3 and F 4 are assumed at the 120/240 V single-
phase locations. Both resistance and reactance components of the circuit element impedances
are used in order to illustrate a more precise procedure and to obtain X/R ratios.

Resistances are usually significant in low-voltage short-circuit current calculations. Their
effect may be evaluated either by a complex impedance reduction or by separate X and R
reductions. The complex reduction leads to the most accurate short-circuit-current magnitude
results (but probably nonconservative X/R ratios). The separate X and R reductions are sim-
pler, conservative, and have the added benefit that they give the best approximation for the
X/R ratio at the fault point. They are illustrated by this example:

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Std 141-1993

4.7.1 Step 1 : Convert all element impedances to per-unit values on a common
base

The assumed base power is 1000 kVA and the base voltage is E b = 480 V:

, w kVA (1000)

base current /, =

73 -E h

_ 1000 • 1000
73-480

= 1202.8 A

base impedance Z h =

a) 13.8 kV source impedance. The short-circuit-current contribution from the 13.8 kV
system will usually be expressed as a symmetrical rms current (in kA) or apparent
power (in MVA), giving a specific X/R ratio. This three-phase short-circuit duty
should be the maximum possible available at the primary terminals of the transformer
and equivalent to the first-cycle symmetrical short-circuit duty. For this example, the
13.8 kV available short-circuit duty is 600 MVA or 25 102 A symmetrical rms at an
X/R ratio of 15. The equivalent R s and X s impedance Z s can be obtained as follows:

E b / 73

480/ 73
1202.8

0.2304 Q

. = base kVA = 1000

f short-circuit kVA 600 000

0.00166 per unit

Since Z s = J(R S ) + (Z s )‘ and X s /R s = 15, the value of R s = Z s /J 1 + (15)' =
0.0001 1 per unit, and the value of X s = 15 • R s = 0.00165 per unit.

b) 1000 kVA transformer impedance. The transformer manufacturer provides the infor-
mation that the impedance is 5.75% on the self-cooled base rating of 1000 kVA, and

the resistance is 1.21% (R T j ). Reactance X = Jz~ - R~ = 5.62% (X T1 ). The perfor-
mance values are as follows:

base kVA _ %R T i _ 1000 1.21
transformer kVA 100 1000 100

base kVA _ %X T1 _ 1000 5.62
transformer kV A 100 1000 100

= 0.0121 per unit

= 0.0562 per unit

161

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CHAPTER 4

c) Cable C’| (300 ft of two 250 kcmil three-conductor copper cables in nonmagnetic
duct). From published tables, the ac resistance /? cl is 0.0541 £2 per conductor per
1000 ft, and the reactance X C1 is 0.0330 £2 per conductor per 1000 ft.

For 300 ft of two paralleled conductors.

R cl = ° ,C ! 541 „’2 QQ = 0.00812 £2

2 • 1000

X C1 = °^ 33Q ^ Q0 = 0.00495 £2

2 ■ 1000

Converting impedances to per unit.

„ actual ohms 0.00812

R r , = = - , = 0.0352 per unit

C1 base ohms 0.2304 F

X _ actual ohms _ 0.00495
Cl base ohms 0.2304

= 0.0215 per unit

d) Cable C 2 (200 ft of three 250 kcmil three-conductor copper cables in magnetic duct).
From published tables, the ac resistance R C2 is 0.0552 £2 per conductor per 1000 ft,
and the reactance Xq 2 is 0.0379 £2 per conductor per 1000 ft.

For 200 ft of three parallel conductors.

^C2

0.0552 • 200
3 • 1000

0.00368 £2

0.0379 • 200
3 • 1000

• 0.00253 £2

Converting impedances to per unit,

„ 0.00368 nm<cy7

Rcl = 0 2304 = °' 01597 P erumt

v 0.00253 nmrios

X C2 = 0 9 304 = 0.01098 perumt

e) Cable C3 (100 ft of one AWG No. 2/0 two-conductor copper cable in magnetic duct).
From published tables, the ac resistance Rq 3 is 0.102 Q/1000 ft, and the reactance
Z C3 is 0.0407 £2/1000 ft.

162

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Std 141-1993

For 100 ft,

^C'3

0.102 • 100
1000

0.0102 Q

0.0407 • 100
1000

0.00407 Q

Converting impedances to per unit,

„ 0.0102

r C3 = 02304 = °- 0443 P er umt
v 0.00407

X C3 = o 93Q4 = °- 01766 P erumt

f) Motor contribution. The running motor loads at motor control center 1 and 2 buses
total 400 hp and 500 hp, respectively. Typical assumptions made for 480 V small
motor groups are that 1 hp = 1 kVA, and the average subtransient reactance is 25%.
The resistance is 4. 167%, based on a typical X/R ratio of 6 .

Converting impedances to per unit on the 1000 kVA base.

base kVA • %R M1 1000-4.167 _

*MI = TTTTTTTTTa - ~ iTvT = a aa . i aa = 0.1042 per unit

motor kVA • 100 400-100

base kVA • %X M] 1000-25 _

*M1 = TZTTTTTTTT - TrvrT = a nn . i An = °' 625 P el ' unlt

motor kVA- 100 400-100

„ 1000-4.167

^M2 = cnn , nn = °- 0833 P er Umt

500 • 100

^M2 -

1000 • 25
500 • 100

= 0.500 per unit

4.7.2 Step 2: Draw separate resistance and reactance diagrams applicable for
fault locations F 1 and F 2 (figures 4-21 and 4-22)

Since the single-phase 120/240 V system has no short-circuit current contributing sources, it
will not be represented in these diagrams.

163

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4.7.3 Step 3: For each fault location reduce R and X networks to per-unit values
and calculate fault current

The reduction of the R and X networks at short-circuit location Fj is shown in figures 4-23
and 4-24. The short-circuit current at F| is then calculated as follows:

The total impedance Z is

Z = Jr 2 + z 2 = 7(0.010 09) 2 + (.048 ll) 2 = 0.049 16 per unit

The total three-phase symmetrical short-circuit current at F| is (E/Z) • base current; that is,

base amperes _ 1202.8

per-unit Z 0.049 16

24 470 A

and the X/R ratio of the system impedance for the short circuit at F] is

X/R

0.048 1 1
0.010 09

4.77

The reduction of the R and X networks at short-circuit location F 2 is shown in figures 4-25
and 4-26. The short-circuit current at F 2 is then calculated as follows:

The total impedance Z is

Z = JR 2 + X 2 = 7(0.0319) 2 + (0.0657) 2 = 0.073 per unit
The total three-phase symmetrical short-circuit current at F 2 is

base amperes _ 1202.8
per-unit Z 0.073

16 480 A

and the X/R ratio of the system impedance for the short circuit at F 2 is

X/R

0.0657

0.0319

2.06

165

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CHAPTER 4

Figure 4-23— Reduction of R network for fault at Fi

0.05785 + 0.6465 + 0.5110

ft 1 = 0. 04811 per unit

Figure 4-24— Reduction of X network for fault at F-|

4.7.4 Step 4: Draw separate resistance and reactance diagrams applicable for
short circuits at the 120/240 V single-phase secondary of the 75 kVA trans-
former, and calculate fault currents

Per-unit calculations of short-circuit currents at the low-voltage side of a single-phase trans-
former connected line-to-line to a three-phase system may continue to use the same base, in
this example 1000 kVA, but as a single-phase base. Impedances in the primary system con-
nected to the transformer have double the values used for three-phase calculations to account
for both outgoing and return paths of single-phase primary currents. This procedure assumes
that the positive and negative sequence impedances are equal.

The total system three-phase short-circuit point impedance, as calculated above for a short
circuit at Fj, consists of R s = 0.0 1 0 1 per unit and X s = 0.048 1 per unit. Since these are line-to-
neutral values, they are doubled to obtain the line-to-line equivalents. Thus R s becomes
0.0202 per unit and X s becomes 0.0962 per unit.

166

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Std 141-1993

• ' ^subtot

■*

f 2

' + 0.0352

' + !

001221 0.09927

0.04607 per unit

| <Rmi = 0-I042
1

0.04607 + 0.1042
^ = 0.0319 per unit

f 2

Figure 4-25— Reduction of R network for fault at F 2

x subtot =

0.05785 0.51098

= 0.07347 per unit

i XMI= 0.625

I L

0.0215

0 07347 + 0.625
0.0657 per unit

Figure 4-26— Reduction of X network for fault at F 2

167

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CHAPTER 4

The single-phase cable circuit C 3 was determined to have a per-unit line-to-neutral resistance
R c 3 equal to 0.0443 and a per-unit line-to-neutral reactance X C3 of 0.017 66 . These values
must also be doubled for the line-to-line short-circuit calculation, and become 0.0886 and
0.0353 per unit, respectively.

The 75 kVA transformer impedance, from a manufacturer’s published tables, is 2.6% on the
base rating of 75 kVA, including the full secondary winding. The impedance components are
1.2% resistance /? T2 and 2.3% reactance A T2 .

The per-unit values on the common 1000 kVA base are as follows:

X T2 -

base kVA

%Rj 2

1000

1.2

transformer kVA

100

base kVA

%x X2

1000

, 2 - 3

transformer kVA

100

0.16 per unit

For a line-to-line short circuit at F 3 across the 240 V secondary winding of the 75 kVA trans-
former, the applicable resistance and reactance diagrams are shown in figures 4-27 and 4-28.
The total impedance Z is

Z = 7(0.2688)? +(0.4382 f = 0.5141 per unit
the total short-circuit apparent power (in kVA) is

base kVA
per-unit Z

1000

0.5141

= 1945 kVA

and the total symmetrical rms short-circuit current is

kVA ( 1000 )
El. l

1945 • 1000
240

= 8104 A

For a line-to-line short circuit across the 120 V secondary of the 75 kVA transformer, the
transformer resistance and reactance values are modified to compensate for the half winding
effect. On the same 75 kVA base rating, impedances of one 120 V winding are obtained from
those of the 240 V winding using a resistance multiplier of approximately 1.5 and a reactance
multiplier of approximately 1.2. These multipliers are typical for a single-phase distribution
class transformer. However, for greater accuracy, the transformer manufacturer should be
consulted.

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R s = 0 0202

RC3 = 0.0886 \ Rf 0 f = 0.2688 per unit

Rj2 = 0- 16

Xs = 0 0962

XC3 = 0.0353 > = 0 4382 per unit

i XT2 = 0.3067

Figure 4-27— Resistance network
for fault at F 3

Figure 4-28— Reactance network for
fault at F 3

For a short circuit at F 4 the resistance and reactance diagrams are shown in figures 4-29 and
4-30. The total impedance Z is

Z = 7(03488^T(a4995^ = 0.6092 per unit
the total short-circuit apparent power (in kVA) is

base kVA
per-unit Z

1000

0.6092

= 1642 kVA

and the total symmetrical rms short-circuit current is

kVA (1000) _ 1642 • 1000
El - l “ 120

13 683 A

0 0202

< Rq 3 = 0 0886 \ Rfot = 0 3488 per unit

< Rj 2 “ 1-5 • 0.16
f =0.24 )

Figure 4-29— Resistance network
for fault at F 4

Xs = 0 0962

X C 3 = 0.0353 \ X tot = 0.4995 per unit

I X J2 =1.2 • 03067
= 0.368

Figure 4-30— Reactance network
for fault at F 4

169

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CHAPTER 4

4.8 Calculation of short-circuit currents for dc systems

The calculation of dc short-circuit currents is essential in the design and application of distri-
bution and protective apparatus used in dc systems. A knowledge of mechanical stresses
imposed by these fault currents is also important in the installation of cables, buses, and their
supports.

As in the application of ac protective devices, the magnitude of the available dc short-circuit
current is the prime consideration. Since high-speed or semi-high-speed dc protective devices
can interrupt the flow of fault current before the maximum value is reached, it is necessary to
consider the rate of rise of the fault current, along with the interruption time, in order to deter-
mine the maximum current that will actually be obtained. Lower speed protective devices
will generally permit the maximum value to be reached before interruption.

The sources of dc short-circuit currents are the following:

a) Generators

b) Synchronous converters

c) Motors

d) Electronic rectifiers

e) Semiconductor rectifiers

f) Batteries

g) Electrolytic cells

Simplified procedures for the calculation of dc short-circuit currents are not well established;
therefore, this chapter can only provide reference to publications containing helpful infor-
mation (see ANSI C97.1-1972, IEEE Std C37.5-1979, IEEE Std C37.41-1988, NEMA
AB 1-1975, and NEMA SG 3-1981).

4.9 References

This standard shall be used in conjunction with the following publications:

ANSI C84. 1-1989, American National Standard Electric Power Systems and Equipment-
Voltage Ratings (60 Hz). 2

ANSI C97. 1-1972, American National Standard for Low- Voltage Cartridge Fuses 600 Volts
or Less.

IEEE Std C37.010-1979, IEEE Application Guide for AC High-Voltage Circuit Breakers
Rated on a Symmetrical Current Basis (ANSI).

“ANSI publications are available from the Sales Department, American National Standards Institute, 1 1 West 42nd
Street, 13th Floor, New York, NY 10036, USA.

3 IEEE publications are available from the Institute of Electrical and Electronics Engineers, Service Center. 445 Hoes
Lane. P.O. Box 1331, Piscataway, NJ 08855-1331, USA.

170

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Std 141-1993

IEEE Std C37.5-1979, IEEE Guide for Calculation of Fault Currents for Application of AC
High-Voltage Circuit Breakers Rated on a Total Current Basis (ANSI). 4

IEEE Std C37. 13-1990, IEEE Standard for Low- Voltage AC Power Circuit Breakers Used in
Enclosures (ANSI).

IEEE Std C37.41-1988, IEEE Standard Design Tests for High-Voltage Fuses, Distribution
Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and Accessories (ANSI).

NEMA AB 1-1975, Molded-Case Circuit Breakers. 5

NEMA SG 3-1981, Low- Voltage Power Circuit Breakers.

4.10 Bibliography

[Bl ] AIEE Committee Report, “Protection of Electronic Power Converters.” AIEE Transac-
tions, vol. 69, pp. 813-829, 1950.

[B2] Beeman, D. L., Ed., Industrial Power Systems Handbook. New York: McGraw-Hill,
1955, chapter 2.

[B3] Crites, W. R., and Darling, A. G., “Short-Circuit Calculating Procedure for DC Systems
with Motors and Generators.” AIEE Transactions (Power Apparatus and Systems), pt. Ill, vol.
73, pp. 816-825, Aug. 1954.

[B4] Dortort, I. K., “Equivalent Machine Constants for Rectifiers.” AIEE Transactions (Com-
munications and Electronics), pt. I, vol. 72, pp. 435M-38, Sept. 1953.

[B5] Dortort, I. K., “Extended Regulation Curves for Six-Phase Double- Way and Double-
Wye Rectifiers.” AIEE Transactions (Communications and Electronics), pt. I, vol. 72,
pp. 192-202, May 1953.

[B6] Electrical Transmission and Distribution Reference Book. East Pittsburgh, PA: Westing-
house Electric Corporation. 1964.

[B7] Greenwood, A., “Basic Transient Analysis for Industrial Power Systems,” Conference
Record, 1972 IEEE Industrial and Commercial Power Systems and Electric Space Heating
Joint Technical Conference, IEEE 72CH0600-7-IA, pp. 13-20.

[B8] Herskind, C. C., Schmidt, A., Jr., and Rettig, C. E., “Rectifier Fault Currents— II,” AIEE
Transactions, vol. 68, pp. 243-252, 1949.

4 IEEE Std C37. 5-1979 has been withdrawn and is out of print; however, copies can be obtained from the IEEE
Standards Department, IEEE Service Center, 445 Hoes Lane. P.O. Box 1331, Piscataway, NJ 08855-1331, USA.

5 NEMA publications can be obtained from the National Electrical Manufacturers Association, 2101 L Street, NW,
Washington, DC 20037, USA.

171

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CHAPTER 4

[B9] Huening, W. C., Jr., Interpretation of New American National Standards for Power
Circuit Breaker Applications. IEEE Transactions on Industry and General Applications, vol.
IGA-5, no. 5, Sept./Oct. 1969.

[B10J Reed, M. B., Alternating Current Circuit Theory , 2nd edition. New York: Harper and
Brothers, 1956.

[Bll| St. Pierre, C. R., Time-Sharing Computer Programs (DATUMS) for Power System
Data Reduction. Schenectady, NY: General Electric Company, 1973.

[B12] Stevenson, W. D., Jr., Elements of Power System Analysis. New York: McGraw-Hill,
1982.

[B13] Wagner, C. E, and Evans, R. D., Symmetrical Components. New York: McGraw-Hill,
1933.

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Std 141-1993

Annex 4A

Typical impedance data for short-circuit studies

(informative)

The following tables and figures appear in this annex:

Table 4A-1, Typical reactance values for induction and synchronous machines, in per-unit of
machine kVA ratings

Table 4A-2, Representative conductor spacings for overhead lines

Table 4A-3, Constants of copper conductors for 1 ft symmetrical spacing

Table 4A-4, Constants of aluminum cable, steel reinforced (ACSR), for 1 ft symmetrical
spacing

Table 4A-5, 60 Hz reactance spacing factor Ag, in ohms per conductor per 1000 ft

Table 4A-6, 60 Hz reactance spacing factor Ag, in ohms per conductor per 1000 ft

Table 4A-7, 60 Hz impedance data for three-phase copper cable circuits, in approximate
ohms per 1000 ft at 75 °C (nonshielded varnished cambric/shielded neoprene insulated
cables)

Table 4A-8, 60 Hz impedance data for three-phase aluminum cable circuits, in approximate
ohms per 1000 ft at 90 °C (cross-linked polyethylene insulated cable)

Figure 4A- 1 , X/R ratio of transformers

Figure 4A-2, X/R range for small generators and synchronous motors (solid rotor and salient
pole)

Figure 4A-3, X/R range for three-phase induction motors

The following tables appear in other chapters:

Table 10-15, BILs and percent impedance voltages at self-cooled (0A) rating for liquid-
immersed transformers (Chapter 10)

Table 10-16, BILs and percent impedance voltage for dry-type transformers (Chapter 10)

Table 13-2, Voltage-drop values of three-phase, sandwiched busways with copper bus bars,
in V/100 ft, line-to-line, at rated current with concentrated load (Chapter 13)

Table 13-3, Voltage-drop values of three-phase, sandwiched busways with aluminum bus
bars, in V/100 ft, line-to-line, at rated current with concentrated load (Chapter 13)

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CHAPTER 4

Table 4A-1 —Typical reactance values for induction and
synchronous machines, in per unit of machine kVA ratings*

*d'

Turbine generators^

2 poles

0.09

0.15

4 poles

0.15

0.23

Salient-pole generators with damper windings^

12 poles or less

0.16

0.33

14 poles or less

0.21

0.33

Synchronous motors

6 poles

0.15

0.23

8-14 poles

0.20

0.30

16 poles or more

0.28

0.40

Synchronous condensers^

0.24

0.37

Synchronous converters^

600 V direct current

0.20

—

250 V direct current

0.33

Individual large induction motors, usually
above 600 V

0.17

—

Smaller motors, usually 600 V and below

See tables 4-1 and 4-2.

NOTE — Approximate synchronous motor kVA bases can be found from motor horsepower ratings
as follows:

0.8 power factor motor — kVA base = hp rating
1.0 power factor motor — kVA base = 0.8 • hp rating

Use manufacturer’s specified values if available,
not normally used in short-circuit calculations.

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Table 4A-2— Representative conductor spacings for overhead lines

Nominal system
voltage
(volts)

Equivalent delta
spacing
(inches)

120

240

480

600

2400

4160

6900

13 800

23 000

34 500

69 000

115 000

204

NOTE — When the cross section indicates conductors are
arranged at points of a triangle with spacings A, B, and C
between pairs of conductors, the following formula may
be used:

equivalent delta spacing = i/,4 • B ■ C

When the conductors are located in one place and the out-
side conductors are equally spaced at distance A from the
middle conductors, the equivalent is 1.26 times the dis-
tance A:

equivalent delta spacing

Ha- A- 2 A

= 1.26A

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CHAPTER 4

Table 4A-3— Constants of copper conductors for 1 ft symmetrical spacing*

Size of conductor

Resistance R at 50 °C,

60 Hz

Reactance X A at 1 ft
spacing, 60 Hz

(cmil)

(AWG No.)

(Q/conductor/1000 ft)

1 000 000

0.0130

0.0758

900 000

0.142

0.0769

800 000

0.0159

0.0782

750 000

0.0168

0.0790

700 000

0.0179

0.0800

600 000

0.0206

0.0818

500 000

0.0246

0.0839

450 000

0.0273

0.0854

400 000

0.0307

0.0867

350 000

0.0348

0.0883

300 000

0.0407

0.0902

250 000

0.0487

0.0922

211 600

4/0

0.0574

0.0953

167 800

3/0

0.0724

0.0981

133 100

2/0

0.0911

0.101

105 500

1/0

0.115

0.103

83 690

0.145

0.106

66 370

0.181

0.108

52 630

0.227

0.111

41 740

0.288

0.113

33 100

0.362

0.116

26 250

0.453

0.121

20 800

0.570

0.123

16 510

0.720

0.126

NOTE— For a three-phase circuit the total impedance, line to neutral, is Z= R + j ( X A + X B ).
Use spacing factors of X B of tables 4A-5 and 4A-6 for other spacings.

176

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Std 141-1993

Table 4A-4— Constants of aluminum cable, steel reinforced (ACSR), for 1 ft

symmetrical spacing*

Size of conductor

Resistance R at 50 °C,

60 Hz

Reactance X A at 1 ft
spacing, 60 Hz

(cmil)

(AWG No.)

(Q/conductor/1000 ft)

1 590 000

0.0129

0.0679

1 431 000

0.0144

0.0692

1 272 000

0.0161

0.0704

1 192 500

0.0171

0.0712

1 113 000

0.0183

0.0719

954 000

0.0213

0.0738

795 000

0.0243

0.0744

715 500

0.0273

0.0756

636 000

0.0307

0.0768

556 500

0.0352

0.0786

477 000

0.0371

0.0802

397 500

0.0445

0.0824

336 400

0.0526

0.0843

266 800

0.0662

0.0945

4/0

0.0835

0.1099

3/0

0.1052

0.1175

2/0

0.1330

0.1212

1/0

0.1674

0.1242

0.2120

0.1259

0.2670

0.1215

0.3370

0.1251

0.4240

0.1240

0.5340

0.1259

0.6740

0.1273

NOTE — For a three-phase circuit the total impedance, line to neutral, is Z = R +j ( X A + X B ).
*Use spacing factors of X B from tables 4A-5 and 4A-6 for other spacings.

177

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Std 141-1993

Table 4A-6— 60 Hz reactance spacing factor X B ,
in ohms per conductor per 1000 ft

Separation (quarter inches)

(inches)

1/4

2/4

3/4

—

-0.072 9

-0.063 6

-0.0571

-0.051 9

-0.047 7

-0.044 3

-0.0412

-0.038 4

-0.035 9

-0.033 9

-0.0319

-0.030 1

-0.028 2

-0.026 7

-0.0252

-0.023 8

-0.022 5

-0.021 2

-0.0201

-0.017 95

-0.016 84

-0.0159

-0.014 94

-0.013 99

-0.013 23

-0.0124

-0.011 52

-0.010 78

-0.010 02

-0.0093

-0.008 52

-0.007 94

-0.007 19

-0.0066

-0.006 05

-0.005 29

-0.004 74

-0.0042

—

-0.0020

—

179

CHAPTER 4

IEEE

Std 141-1993

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SHORT-CIRCUIT CURRENT CALCULATIONS

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Table 4A-8— 60 Hz impedance data for three-phase aluminum cable circuits, in approximate ohms per 1000 ft at 90 °C

(a) Three single conductors

IEEE

Std 141-1993

CHAPTER 4

IT)

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SHORT-CIRCUIT CURRENT CALCULATIONS

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Std 141-1993

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Resistance values (R[) at lower aluminum temperatures (T L ) are obtained by the formula

IEEE

Std 141-1993

CHAPTER 4

SELF- COOLED TRANSFORMER RATING IN MVA
Source: Based on IEEE Std C37.010-1979.

Figure 4A-1 — X/R ratio of transformers

NAMEPLATE hp

Source: Reprinted from IEEE Std C37.010-1979. Source: Reprinted from IEEE Std C37.010-1979.

Figure 4A-2— X/R range for small Figure 4A-3— X/R range for

generators and synchronous motors three-phase induction motors

(solid rotor and salient pole)

184

Chapter 5

Application and coordination of protective devices

5.1 Purpose

The system and equipment protective devices guard the power system from the ever-present
threat of damage caused by overcurrents and transient overvoltages that can result in equip-
ment loss, system failure, and injury to personnel. This chapter presents the principles of ade-
quate system and equipment protection by introducing the many protective devices and their
applications, special problems, system conditions associated with transient overvoltages,
sound engineering techniques of protective-device application and coordination, and sug-
gested maintenance and testing procedures for circuit interrupting and protective devices. The
subject of protection and coordination of industrial power systems is covered in additional
detail in IEEE Std 242-1986 [B57]. 1

5.1.1 Considering plant operation [B2]

Industrial plants vary greatly in the complexity of electric distribution systems. A small plant
may have a simple radial design with low- voltage fuse protection only, whereas a large plant
complex may incorporate an intricate network of medium- and low-voltage distribution sub-
stations, uninterruptible power sources, and in-plant generation required to operate in parallel
with or isolated from local utility networks. At an early design stage, the plant engineering
representatives should meet with the local power company to review and resolve the require-
ments of both the plant and the utility.

The need for higher production from industrial plants has created demands for greater power
system reliability. Trends to network systems and parallel operation with utilities have pro-
duced sources that have extremely high overcurrents during fault conditions. These trends
lead to the development of new equipment standards.

The high costs of power distribution equipment and the time required to repair or replace
damaged equipment, such as transformers, cable, high-voltage circuit breakers, etc., make it
imperative that serious consideration be given to system-protection design.

The losses associated with an electrical service interruption due to equipment or system
failures vary widely with different types of industries. For example, a service interruption in
a machining operation means loss of production, loss of tooling, and loss from damaged
products. Likewise, a service interruption in a chemical plant can cause loss of product and
create major clean-up and restart problems. To avoid a disorderly shutdown, which can be
both hazardous and costly, it may be necessary to tolerate a short-time overload condition
and the associated reduction in life expectancy of the affected electric apparatus. Other indus-
tries such as refineries, paper mills, automotive plants, textile mills, steel mills, and food-pro-
cessing plants are similarly affected, and losses can represent a substantial expense. Some

The numbers in brackets preceded by the letter B correspond to those in the bibliography in 5.10.

185

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CHAPTER 5

types of loads can tolerate an interruption, whereas for other types of loads involving contin-
uous processes and complex automation, even a momentary dip in voltage can be as serious
as a complete service interruption. Thus the nature of the industrial operation is a major con-
sideration in determining the degree of protection that can be justified.

5.1.2 Equipment capabilities

In addition to meeting the demands of overall system performance as dictated by the nature
of the load, the protective devices must operate in conjunction with the associated circuit
interrupters so as to afford protection to other power system equipment components. Trans-
formers, cable, busway, circuit breakers, and other switching apparatus all have short-circuit
withstand limits as established by the National Electrical Manufacturers Association
(NEMA) and the American National Standards Institute (ANSI).

When a fault condition occurs, these devices, although perfectly intact, may be connected in
series in the same circuit and subjected to severe thermal and magnetic stresses accompany-
ing the passage of high-magnitude short-circuit current through their conducting parts. An
important function of the system protective devices is to initiate operation of the circuit inter-
rupter responsible for isolating the fault so that the other equipment connected in the same
circuit is not stressed beyond safe limits. Otherwise, the initial fault condition can affect far
more than the specific circuit to be isolated, and a widespread outage can result.

The design engineer should examine the performance capability of all the individual system
equipment components and not just the process sensitivity to local outages when justifying
the protection to be applied. System and equipment protection is one of the most important
items in the process of system planning, and enough time should be allowed in the early
stages of a system design to properly investigate the selection and application of the protec-
tive devices.

5.1.3 Importance of responsible planning

Some industrial plants, because of their size or the nature of their operations, are able to
maintain electrical engineering staffs capable of the design, installation, and maintenance of
an efficient protective system; other plants may find it more economical to engage competent
engineering advice and services from consultants. This work is specialized and often very
complex, and it is neither safe nor fair to expect the operating engineer to do it as a sideline.
Modern computerized methods of calculating fault currents on complex systems are available
from consulting firms and manufacturers. These provide accurate information essential for
making decisions relative to the protection design in a short period of time [B67].

Protection in an electric system is a form of insurance. It pays nothing as long as there is no
fault or other emergency, but when a fault occurs it can be credited with reducing the extent
and duration of the interruption, the hazards of property damage, and personnel injury. Eco-
nomically, the premium paid for this insurance should be balanced against the cost of repairs
and lost production. Protection, well integrated with the class of service desired, may reduce
capital investment by eliminating the need for equipment reserves in the industrial plant or
utility supply system.

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While the protective devices are the guardians of the power system, the industrial electrical
engineer must be the custodian of the protection system. Adequate and regular maintenance
and testing should be carried out, as well as a review of the protection scheme when major
system changes occur. Integrity of the system protection and, thereby, the system perfor-
mance, requires a continuing effort if it is to be preserved.

5.1.4 Personnel safety

In all the foregoing considerations of plant design and operation, safety to plant personnel
must be of primary concern. The design engineer should be familiar with the latest revisions
of codes and standards, such as the National Electrical Code (NEC) (ANSI/NFPA 70-1993
[BIO]), the National Electrical Safety Code (NESC) (Accredited Standards Committee C2-
1993 [Bl], and other applicable state and local codes which apply to personnel safety. In
addition, there are federal regulations prepared by the Occupational Safety and Health
Administration (OSHA) which must be adhered to.

5.2 Analysis of system behavior and protection needs

5.2.1 Nature of the problem

It would be neither practical nor economical to build a fault-proof power system. Conse-
quently, modern systems are designed to provide reasonable insulation, clearances, etc., but a
certain number of faults must be tolerated during the life of the system. Even with the best
design possible, materials deteriorate and the likelihood of faults increases with age. Every
electrical system has the potential to experience short-circuit conditions. A sound knowledge
of the effect of such conditions on system voltages and currents is necessary in designing pro-
tective schemes. A reliable protective system is one which is properly designed, regularly
maintained, and does not have unnecessarily complex relaying schemes.

Operating records show that the majority of electric circuit faults originate as phase-to-
ground failures. Protective devices should detect three-phase, phase-to-phase, double-phase-
to-ground, as well as single phase-to-ground short circuits. There are two general classifica-
tions of three-phase systems: (1) ungrounded systems, and (2) grounded systems, in which
one conductor, generally the neutral, is grounded either solidly or through an impedance.
Both classifications of systems are subject to all the aforementioned types of faults, but the
severity of those faults involving ground depends to a large extent on the method of system
grounding and the magnitude of the grounding impedance.

5.2.2 Grounded and ungrounded systems

The general subject of system grounding (see IEEE Std 142-1991 [B56]) is treated from the
viewpoint of system design in Chapter 7, and it is only necessary to observe here the effect on
basic relaying methods of the choice between a grounded and an ungrounded system.

In grounded systems, phase-to-ground faults produce currents of sufficient magnitude to
operate ground-fault-responsive overcurrent relays, which automatically detect the fault,

187

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CHAPTER 5

determine which feeder has failed, and initiate the opening of the correct circuit interrupters
to de-energize the faulted portion of the system without interrupting service to healthy cir-
cuits. If the system neutral is grounded through a properly chosen impedance, the value of the
ground-fault current can be restricted to a level that will avoid extensive damage at the point
of the fault, yet be adequate for ground-fault relaying. In addition, the voltage dip caused by
the flow of ground-fault current will be substantially reduced.

In ungrounded systems, as shown in figure 5- 1(a), phase-to-ground faults produce relatively
insignificant values of fault current. In a small, isolated-neutral industrial installation, the
ground-fault current for a single line-to-ground fault may be well under one ampere, while
the largest plant, containing miles of cable to provide electrostatic capacitance to ground,
may produce as much as 20 A of ground-fault current. Overcurrent relays are not normally
used to locate and remove such faults because they do not have the sensitivity to detect this
low fault current, and because of the complexity of current flow pattern resulting from the
fact that the source of the ground current is the distributed capacitance to ground of the
unfaulted conductors. It is possible, however, to provide phase-to-ground voltage relays that
will operate an alarm on the occurrence of a ground fault, but that cannot provide any indica-
tion of its exact location. The voltage and current distribution for normal operation and for a
single-phase-to-ground fault (phase A) condition for an ungrounded system are shown in fig-
ure 5- 1(b) and (c), respectively.

The one advantage of an ungrounded system lies in the possibility of maintaining service on
the entire system, including the faulted section, until the fault can be located and the equip-
ment shut down for repair. This advantage should be balanced against such disadvantages as
the impossibility of relaying the fault automatically, the difficulty of locating the fault, the
continuation of burning and the escalation of damage at the point of the fault, the continued
overstressing of the insulation of the unfaulted phases (1.73 times operating voltage in the
case of solid ground faults and perhaps much more in the case of intermittent ground faults),
and the hazard of multiple ground faults and transient overvoltages. High-resistance ground-
ing should be considered as a preferred alternate. It should be noted that the single-pole inter-
rupting ratings of multiple-pole overcurrent devices must be evaluated wherever these
systems are utilized.

5.2.3 Distortion of phase voltages and currents during faults

Balanced three-phase faults do not cause voltage distortion or current unbalance. Figure 5-2
shows the balanced conditions, both before and after a fault is applied on a system having an
X/R ratio of approximately 1.7, which corresponds to an angle of 60 degrees between phase
voltage and current or a 50% fault-circuit power factor. This condition would be realized by
closing all three poles of switch SW 2 in figure 5- 1(a). Other types of faults, such as phase-to-
phase, single-phase-to-ground, and two-phase-to-ground, cause distorted voltages and unbal-
anced currents. The voltage distortion is greatest at the fault and minimum at the generator or
source.

Currents and voltages that exist during a fault vary widely for different systems, depending
on type and location of the fault and the impedance of the system grounding connection. The
vector diagrams of figure 5-3 shows voltage and current relations that exist for different types

188

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

(b) Normal distribution of voltage
and current phasors prior
to fault application

Figure 5-1 —Analysis of steady-state conditions on an ungrounded system
before and after the occurrence of a ground fault

of faults on a solidly grounded system in which the currents lag the voltages by 60 degrees.
Load currents are not included.

These diagrams are typical of the fault conditions that cause protective devices to operate.
The characteristics of the voltage distortion that accompanies a fault are used to enable spe-
cial types of relays to discriminate between different types of faults having otherwise similar
current conditions. Some of these special devices will be discussed in further detail later in
this chapter. The distortion can be greater or less than that shown, depending on the imped-
ance of the fault and its distance from the relay. The small voltage drop shown between the
faulted phases represents the fault impedance (arc) voltage drop plus the voltage drop in the
system conductors due to the flow of fault current between the relay and the fault point.

189

IEEE

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CHAPTER 5

(a) Normal conditions
with load applied

Figure 5-2— Voltage and current phasor relationships
for a balanced fault condition

5.2.4 Analytical restraints

The one-line diagram commonly used to represent three-phase systems is a very useful ana-
lytical tool when its limitations are properly observed. Its validity is limited to symmetrical
three-phase loading of electrical systems.

One-line diagrams, for example, provide no means for properly representing the effect of
single-phase loads on the operation of the system or the protective devices. Likewise, the
influence of surge-protection equipment acting independently in any of the three phases
cannot be correctly evaluated.

In the case of a line-to-ground fault on a three-phase system, the opening of that phase pro-
tector alone alters the system symmetry. Examination of a more precise three-phase diagram
for a three-wire system reveals that it is still possible for current to flow through the remain-
ing phases via the line-to-line connected paths at the load apparatus, and then to ground at the
fault point. In four-wire systems, the opening of the phase protector effectively removes the
fault and permits single-phase loads on the unfaulted phases to operate normally. However,
three-phase motor loads will be subjected to unbalanced voltages resulting in abnormal
heating.

Determining how much current continues to flow to the ground-fault after opening of one
phase protector in a three-wire system is a complex problem due to the alteration in system
symmetry and introduction of additional variable impedances. However, it is generally a
much lower value than the initial line-to-ground fault current and, hence, it can take the

190

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

(a) Phase-to-phase fault between (b) Two-phase-to-ground fault between

phases B and C on ungrounded ground and grounded system

system [close poles B and C [close SW 3 and poles B and C

of SW 2 in figure 5-1 (a)] of SW 2 in figure 5-1 (a)]

Figure 5-3— Voltage and current phasor relationships for
various unbalanced fault conditions (system X/R = 1.7)

191

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CHAPTER 5

remaining protectors some time to sense and clear the circuit. Substantial heat with associ-
ated damage can be generated at the fault point before complete isolation of the circuit is
accomplished.

By simultaneously opening all phases, such as by ground-fault protection, the three-phase
symmetry is not altered and the condition described above need not be given consideration.

5.2.5 Practical limits of protection

When the industrial power system is in normal operation, all parts should have some form of
automatic protection. However, some fault possibilities may be legitimately considered too
improbable to justify the cost of specific protection. Before accepting a risk on this basis
alone, the magnitude of the probable damage should also be seriously considered. Too much
protection might be provided for failures that occur frequently but cause only minor difficul-
ties, while rare but serious causes of trouble might be neglected. For example, internal trans-
former failures rarely occur, but the consequences may be very serious since such faults can
cause fires and endanger personnel and equipment.

Most systems have some flexibility in the manner in which circuits are connected. The vari-
ous possible arrangements should be considered in planning the protection system so as not
to leave some emergency operating condition without protection. Some types of systems have
so many possible operating combinations that protection cannot be applied to operate prop-
erly for all conditions. In such cases, the operating connections for which the protection is
inadequate should be avoided.

5.3 Protective devices and their applications [B23], [B42], [B65]

5.3.1 General discussion

Power system protective devices provide the intelligence and initiate the action that enables
circuit switching equipment to respond to abnormal or dangerous system conditions. Nor-
mally, relays control power circuit breakers rated above 600 V and current-responsive self-
contained elements operate multiple-pole low-voltage circuit breakers to isolate circuits
experiencing overcurrents on any phase. Similarly, fuses function alone or in combination
with other suitable means to properly provide isolation of faulted or overloaded circuits. In
other cases, special types of relays that respond to abnormal electric system conditions may
cause circuit breakers or other switching devices to disconnect defective equipment from the
remainder of the system.

In systems employing circuit breakers, other than those with direct acting devices that use
fault current to power relaying and trip functions, there is always a risk that during a fault the
system voltage can drop suddenly to a value too low for the protective devices to function.
For this reason station battery sets, or capacitor trip devices, are usually employed to provide
tripping energy. It is important to be able to test the circuit breaker and relay systems during
power outages, whether planned or accidental. The stored energy system should be designed
to provide these functions. In large systems with centralized switchgear, large battery sets are

192

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

usually provided. Capacitor trip devices are often used in small low-voltage systems where
manual charging of springs can supply the stored energy during prolonged power interrup-
tions. Capacitor trips are often applied in small remote medium-voltage systems. In systems
where direct acting devices are used for overcurrent protection, functions, such as undervolt-
age protection, sensitive ground-fault protection, or other similar protection, may require
stored-energy tripping sources. (See Chapter 10, 10.3.6 Control Power.)

The following is a brief description of the types and characteristics of relays and other protec-
tive devices most commonly used in industrial plant power systems, along with some brief
application considerations. A list of relay device numbers referenced with respective device
functions, taken from IEEE Std C37. 2-1991 [B35], appears in the annex at the end of this
book.

5.3.2 Overcurrent relays 2

The most common relay for short-circuit protection of the industrial power system is the
overcurrent relay, as shown in figure 5-4. The overcurrent relays used in the industry are typ-
ically of the electromagnetic attraction, induction, solid-state, or bimetallic element types.
Relays with bimetallic elements used for thermal overload protection are discussed in 5.3.15.
The simplest overcurrent relay using the electromagnetic attraction principle is the solenoid
type. The basic elements of this relay are a solenoid wound around an iron core and steel
plunger or armature that moves inside the solenoid and supports the moving contacts. Other
electromagnetic-attraction-type relays have hinged armatures or clappers of different shapes.
These relays operate without any intentional time delay, usually within one-half cycle, and
are called instantaneous overcurrent relays. Device 50. The construction of the induction
disk-type overcurrent relay is similar to a watthour meter since it consists of an electromagnet
and a movable armature, which is usually a metal disk on a vertical shaft restrained by a
coiled spring. The relay contacts are operated by the movable armature (figure 5-5).

The pickup or operating current for all overcurrent relays is adjustable. When the current
through the relay coil exceeds a given setting, the relay contacts close and initiate the circuit
breaker tripping operation. The relay operates on current from the secondary of a current
transformer.

When the overcurrent is of a transient nature, such as that caused by the starting of a motor or
some sudden overload of brief duration, the circuit breaker should not open. For this reason,
induction disk overcurrent relays, Device 51, are used since they have an inherent time delay
that permits a current several times in excess of the relay setting to persist for a limited period
of time without closing the contacts. If a relay operates faster as current increases, it is said to
have an inverse-time characteristic. Overcurrent relays are available with inverse, very
inverse, and extremely inverse time characteristics to fit the requirements of the particular
application. There are also definite minimum-time overcurrent relays that have an operating
time that is practically independent of the magnitude of current after a certain current value
is reached. Induction disk overcurrent relays have a provision for variation of the time

2 Figures 5-4 and 5-5 show different types of relays. This Recommended Practice does not intend to imply that the
manufacturers who contributed photographs for these figures make the only, or the preferred, instrument of this type.

193

IEEE

Std 141-1993

CHAPTER 5

Figure 5-4— Typical solid-state overcurrent relay

fOP PIVOT

TAP SFI FCTOH

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Figure 5-5— Induction-disk overcurrent relay with instantaneous attachment
(relay removed from drawout case)

194

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

adjustment and permit change of operating time for a given current. This adjustment is called
the time lever or time dial setting of the relay. Figure 5-6 shows the family of time current
operating curves available with a typical inverse-time overcurrent relay. Such curves nor-
mally employ log-log scales to cover a wide range of time and current. Similar curves are
published for other overcurrent relays having different time-delay characteristics. As is appar-
ent, it is possible to adjust the operating time of relays. This is important since they are nor-
mally used to selectively trip circuit breakers that operate in series on the same system circuit.
With increasing current values, the relay operating time will decrease in an inverse manner
down to a certain minimum value. Figure 5-7 shows the characteristic curves of inverse (A),
very inverse (B), and extremely inverse (C), time relays when set on their minimum and max-
imum time dial positions. It also shows the characteristics of the instantaneous element (D)
that are usually supplied in these relays.

Overcurrent relays, and many other relays as well, are now available that use solid-state com-
ponents to provide their operating characteristics. These are referred to as solid-state relays.
Initial designs offered operating characteristics and adjustability features that matched those
of their electromechanical (EM) predecessors in order to gain user familiarity and acceptance
with the new design. There were early concerns regarding reliability, repeatability, and accu-
racy, but solid-state relays have been proven by many years of field service. The technology
has offered freedom from some of the limitations of EM relays and some of the advantages
offered are

a) Low burden levels placed on instrument transformers;

b) Very fast reset times (not limited by disk inertia);

c) Ability to control the shape of time-current/voltage characteristics;

d) Accurate, predetermined operating set points.

In addition, many new features not previously available are now being offered, such as mul-
tiple-phase elements and multiple functions contained in a single relay enclosure as well as
the ability to communicate to a remote location.

5.3.3 Overcurrent relays with voltage restraint or voltage control,

Device 51V [B22]

A short circuit on an electric system is always accompanied by a corresponding voltage dip,
whereas an overload will cause only a moderate voltage drop. Therefore, a voltage-restrained
or voltage-controlled overcurrent relay is able to distinguish between overload and fault con-
ditions. A voltage-restrained overcurrent relay is subject to two opposing torques, an operat-
ing torque due to current and a restraining torque due to voltage. As such, the overcurrent
required to operate the relay is higher at normal voltage than it is at reduced voltage. A volt-
age-controlled overcurrent relay operates by virtue of current torque only, the application of
which is controlled by a voltage element set to operate at some predetermined value of volt-
age. Such relay characteristics are useful where it is necessary to set the relay close to or
below load current, while retaining certainty that it will not operate improperly on normal
load current.

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1 2 3 4 5 6 7 8 9 10 20 30 40 SO

MULTIPLES OF PICK-UP SETTING

Figure 5-6— Time-current characteristics of a typical
inverse-time overcurrent relay

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5.3.4 Directional relays

5.3.4.1 Directional overcurrent relay, Device 67

Directional overcurrent relays consist of a typical overcurrent unit and a directional unit that
are combined to operate jointly for a predetermined phase angle and magnitude of current. In
the directional unit, the current in one coil, the operating element, is compared in phase-angle
position with a voltage or current in another coil of that unit, the polarizing element. Such a
relay operates only for current flow to a fault in one direction and will be insensitive to cur-
rent flow in the opposite direction. The overcurrent unit of the directional overcurrent relay is
practically the same as for the usual overcurrent relay and has similar definite time, inverse,
very inverse, and extremely inverse time-current characteristics. The directional overcurrent
relays can be supplied with voltage restraint on the overcurrent element.

The most commonly used directional relays are usually directionally controlled; that is, the
overcurrent unit is inert until the directional unit detects the current in the tripping direction
and releases or activates the overcurrent unit. Many directional relays are equipped with
instantaneous elements, which may be either directional or non-directional. Unless it is possi-
ble to determine the direction of the fault by magnitude alone, the nondirectional instanta-
neous tripping feature should not be used.

5.3. 4. 2 Directional ground relay, Device 67N

The grounded-neutral industrial power system consisting of parallel circuits or loops may use
directional ground relays, which are generally constructed in the same manner as the direc-
tional overcurrent relays used in the phase leads. To properly sense the direction of fault cur-
rent flow, they require a polarizing source that may be either potential or current as the
situation requires. Obtaining a suitable polarizing source requires special consideration of the
system conditions during faults involving ground and a unique application of auxiliary
devices.

5.3.4.3 Directional power relay, Device 32

The directional power relay is, in principle, a single-phase or three-phase contact-making
wattmeter and operates at a predetermined value of power. It is often used as a directional
overpower relay set to operate if excess energy flows out of an industrial plant power system
into the utility power system, or to protect generators from “motoring.” Under certain condi-
tions it may also be useful as an underpower relay to separate the two systems if the power
flow drops below a predetermined value. Care should be used in the application of single-
phase power relays because they may cause a false trip operation for certain power factor val-
ues.

5.3.5 Differential relays, Device 87

All the previously described relays have the common characteristic of adjustable settings to
operate at a given value of some electrical quantity, such as current, voltage, frequency,
power, or a combination of current and voltage or current and phase angle. There are other

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fault-protection relays that function by virtue of continually comparing two or more currents
[figure 5-8(a)]. Fault conditions will cause a change of these compared values with reference
to each other and the resulting differential current can be used to operate the relay. However,
current transformers have a small error in ratio and phase angle between the primary and sec-
ondary currents, depending upon variations in manufacture, the magnitude of current, and the
connected secondary burden. These errors will cause a differential current to flow even when
the primary currents are balanced. The differential current may become proportionately larger
during fault conditions, especially when there is a dc component present in the fault current.
The differential relays, of course, must not operate for the highest difference or error current
that can flow for a fault condition external to the protected zone. To provide this feature, the
percentage-type differential relay. Device 87, illustrated at right of figure 5-8(a), has been
developed; it has special restraint windings to prevent improper operation due to the error
currents on heavy through fault conditions, while providing very sensitive detection of low-
magnitude faults inside the differentially protected zone.

5.3.5. 1 Differential protection of motors and generators

The percentage differential relay shown at right in figure 5-8(a) can be selected with restraint
coils to provide a restraining torque of 10% to 25% of the through current on external faults,
but produce zero restraint on internal faults.

Another form of motor differential protection involves the routing of the machine phase and
neutral leads of each phase through a window-type current transformer as shown in
figure 5-8(b). Under normal conditions, the magnetizing flux produced by the currents in
each lead adds to zero and no output is produced. A fault in any winding will result in the
fault current flowing in only one of the leads, causing a differential current (and flux) that
will, in turn, produce an output signal. The single relay, a conventional instantaneous overcur-
rent, and current transformer employed per phase in this scheme is less expensive, although
additional machine terminal box space for neutral conductor cabling is required.

5.3. 5. 2 Differential protection of a two-winding transformer bank

When differential relays are used for transformer protection, the inherent characteristics of
power transformers introduce a number of problems that do not exist in generators and
motors. If the current transformer secondary currents on the two sides of the transformer dif-
fer in magnitude by more than the range provided by the relay taps provided, the relay cur-
rents can be altered by means of auxiliary current transformers. If the transformer has a delta-
wye connection, the high-voltage and low-voltage currents are not in phase; however, the sec-
ondary currents can be brought into phase by connecting the current transformers in delta on
the wye side, and in wye on the delta side. Some microprocessor-type differential relays take
the transformer delta- wye shift into account internally and delta-connected CTs are not nec-
essary. The differential output signals of the current transformers are subject to the same
errors as discussed above for generators. In addition, a significant trip current can be observed
at the relay input during transformer energization due to the primary magnetizing inrush cur-
rent. This is why special percentage differential relays must be used. The best protection can
be provided by using the harmonic restraint-type relay. This relay typically has a filter to the
operating coil that blocks the harmonic currents, and a filter to the restraint coil that passes

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(a) Using percentage-type differential relays (Device 87)
or time-delay overcurrent relays (Device 51)

(b) Using instantaneous relays (Device 50), for motors only

Figure 5-8— Arrangements for motor and generator differential protection

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only harmonic currents. Using this technique, undesired operation on magnetizing inrush cur-
rents is prevented while retaining good sensitivity for fault conditions.

5.3. 5.3 Differential protection of buses

Large industrial power system buses often have sectionalizing circuit breakers so that a fault
in one of the bus sections can be isolated without involving the remaining sections. Each of
the bus sections or the whole bus, where it is not sectionalized, can be provided with differen-
tial relay protection, which isolates the bus section involved in case of an internal fault.

Differential bus protection distinguishes between internal and external fault by comparing the
magnitudes of the currents flowing in and out of the protected bus. The major differences
between bus protection and generator or transformer protection are in the number of circuits
in the protected zone and in the magnitude of currents involved in the various circuits.
Figure 5-9 shows phase and ground differential protection of an eight-circuit bus using over-
current relays. This method, of course, is subject to the same disadvantages discussed in the
preceding paragraphs and is rarely used. Other more acceptable types of bus-protective relays
are normally used, including the differential voltage relay, the percentage differential relay,
and the linear coupler.

a) Differential voltage relay. The most common method of bus protection is the differ-
ential voltage relay. This scheme uses through-type iron-core current transformers.
The problem of current-transformer saturation is overcome by using a voltage-
responsive (high-impedance) operating coil in the relay [B25].

b) Percentage differential relay. Where the number of circuits connected to the bus is
relatively small, relays using the percentage differential principle similar to the trans-
former differential relay may be used. The problem of application of percentage dif-
ferential relays for bus protection, however, increases with the number of circuits
connected to the bus. All current transformers supplying the relays must have identi-
cal ratios and characteristics. Variations in the characteristics of the current trans-
formers, particularly the saturation phenomena under short-circuit conditions,
present the greatest problem to this type of protection and often limit it to applica-
tions where only a limited number of feeders are present.

c) Linear coupler [B31], The linear-coupler bus-protection scheme eliminates the diffi-
culty due to differences in the characteristics of iron-core current transformers by
using air-core mutual inductances. Since it does not contain any iron in its magnetic
circuit, the linear coupler is free of any dc or ac saturation. The linear couplers of the
different circuits are connected in series and produce voltages that are directly pro-
portional to the currents in the circuits. For normal conditions, or for external faults,
the sum of the voltages produced by linear couplers is zero. During internal (bus)
faults, however, this voltage is no longer zero and operates a sensitive relay to trip all
circuit breakers to clear the bus fault.

Bus protection using differential voltage relays or linear couplers is not limited as to
number of source and load feeders, and in general is faster in operation than protec-
tion using the percentage differential principle. It should be noted that linear couplers

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TO SOURCE TO SOURCE

OF POWER OF POWER

FEEDERS

Figure 5-9— Phase and ground protection of an eight-circuit bus
using standard induction-disk overcurrent relays

or current transformers used for differential voltage relays cannot be used for other
purposes. Separate current transformers are required for line relaying and metering.

5.3.6 Current balance relay, Device 46

A phase-balance current-comparison relay or negative-sequence current relay provides sensi-
tive unbalanced-phase-current protection for rotating machinery, such as generators and
motors. In applying these relays it is assumed that under normal conditions the phase currents
in the three-phase supply to the equipment and the corresponding output signals from each
phase current transformer are balanced. Should an open circuit develop in any of the phases,
or should the loads become sufficiently unbalanced, the currents will become unbalanced and
the relay will operate. The phase-balance current relay affords protection against damage to
the motor or generator due to single-phase operation. This type of protection is not provided
for by other relays. Another current-balance type of differential protection for motors, which
is both simple and relatively inexpensive, is provided by the use of a single current trans-
former zero-sequence relay scheme and is discussed further in 5. 3. 7. 2.

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5.3.7 Ground-fault relaying [B27], [B78]

5.3.7. 1 Residual connection

Where the industrial power system neutral is intentionally grounded to allow ground-fault
current of a few hundred amperes or greater to flow in the conductors, ground relaying may
be used to provide improved protection. This is often an overcurrent relay connected in
the common lead of the wye-connected secondaries of three line-current transformers.
Figure 5-10 shows the typical current transformer and relay connections for this application.
When used on four-wire systems, an additional current transformer in the neutral conductor is
required to balance the residual signal of the normal line-to-neutral load currents. The ground
relay can be set to pick up at a much lower current value than the phase relays because there
is no current flowing in the residual circuit due to normal load current. However, when large
ratio current transformers are used, the sensitivity may be limited by the minimum tap setting
available on most relays.

Figure 5-10— Standard arrangement for
residually connected ground relay

Overcurrent relays used for ground-fault protection generally are the same as those used for
phase-fault protection, except that a more sensitive range of minimum operating current val-
ues is possible since they see only fault currents. Relays with inverse or very inverse time
characteristics are best suited for ground- fault relays since they provide a more constant
operating time over the fault current range. Precaution should be used, however, in applying
this type of residually connected ground relay, since it is subject to nuisance operation due to
error currents arising from current transformer saturation and unmatched characteristics in
the manner described for differential relays. Often the optimum speed and sensitivity of a
residual ground relay must be compromised because of this.

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5.3. 7. 2 Zero-sequence sensor (core balance)

An improved type of ground-fault protection can be obtained by a zero-sequence relay
scheme in which a single window-type current transformer is mounted so as to encircle all
three phase conductors, as illustrated in figure 5-11. On four- wire systems with possible
unbalanced line-to-neutral loads, the neutral conductor must also pass through the current
transformer window. Only circuit faults involving ground will produce a current in the cur-
rent-transformer secondary to operate the relay. Since only one current transformer is
employed in this method of sensing ground-faults, the relaying is not subject to current-trans-
former errors due to ratio mismatch or dc saturation effects; however, ac saturation can cause
appreciable error. Therefore, each relay-current transformer combination should be tested
before being applied in order to be assured of predictable performance. This scheme is widely
applied on 5 kV and 15 kV systems, and is also used on low-voltage systems for improved
protection. It is also often used as an economical alternative to differential protection for large
motors on grounded systems.

Figure 5-1 1 —Relay and current-transformer connection
for zero-sequence ground relay

Some solid-state zero-sequence relays are available to protect 600 V and 480 V systems from
arcing ground faults. Arcing ground faults extinguish and then restrike for short periods dur-
ing individual voltage half-wave periods. Some ground-fault relays may reset after each cur-
rent impulse and never trip. This will permit a considerable amount of damage to accumulate.
There are other relays having memory characteristics that integrate the sensed current
impulses with time and will trip when the pickup setting is reached. This type of relay should
be used.

5.3.7.3 Neutral connected relaying

A time overcurrent relay. Device 51G, connected to a current transformer located in the
grounded neutral of a transformer or generator, provides a convenient, low-cost method of

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detecting ground faults. Since only ground-fault currents will flow in this relay, it can be set
to operate on very low values of current. This scheme is widely applied on 5 kV and 15 kV
systems where low-resistance grounding is frequently used, and the fault current may be as
low as 200 A. The relay can be set to minimum values of current pickup and time delay to be
selective with load-side feeder ground-fault relays.

This scheme is also used on solidly grounded, 480 V, three-phase three-wire and four-wire
systems. In four- wire systems where two transformers are operated in parallel or in a second-
ary selective scheme, special considerations are necessary [B29]. The relay can be set to
operate on low values of current and time delay that will be selective with the feeder ground-
fault devices. When there is no ground-fault device on the feeders, the relay pickup and time
delay should be set to be selective with the trip characteristic of the largest feeder phase over-
current device.

Another form of ground-fault protection is when the neutral resistor is sized to limit the
ground-fault current to a few amperes, that is, 1-10 A. This method, known as high-resistance
grounding, limits the damage at the fault site such that the fault is not automatically cleared,
but is detected and an alarm initiated. An overvoltage relay. Device 59G, is used, which is
connected across the resistor and senses the voltage that will appear across it only during
ground faults [B24], Additional information on grounding methods can be found in IEEE Std
142-1991 [B56],

5.3.8 Synchronism-check and synchronizing relays, Device 25

The synchronism-check relay is used to verify when two ac circuits are within the desired
limits of frequency and voltage phase angle to permit them to operate in parallel. These relays
should be employed in switching applications on systems known to be normally paralleled at
some other location so that they are only checking that the two sources have not became elec-
trically separated or displaced by an unacceptable phase angle. The synchronizing relay, on
the other hand, monitors two separate systems that are to be paralleled, automatically initiat-
ing switching as a function of the phase-angle displacement, frequency difference (beat fre-
quency), and voltage deviation, as well as the operating time of the switching equipment, to
accomplish interconnection when conditions are acceptable. An example of this application is
a plant generating its own power with a parallel-operated tie with a utility system. The utility
end of the tie line must have synchronizing relays that will check conditions on both systems
prior to paralleling and initiate the interconnection so as to avoid any possibility of tying with
the industrial plant generators out of phase.

5.3.9 Pilot-wire relays, Device 87L [B23], [B30]

The relaying of tie lines, either between the industrial system and the utility system or
between major load centers within the industrial system, often presents a special problem.
Such lines should be capable of carrying maximum emergency load currents for any length of
time, and they should be removable from service quickly should a fault occur. A type of dif-
ferential relaying called pilot-wire relaying responds very quickly to faults in the protected
line. Faults are promptly cleared, which minimizes line damage and disturbance to the sys-
tem, yet the relay is normally unresponsive to load currents and to currents flowing to faults

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in other lines and equipment. The various types of pilot-wire relaying schemes all operate on
the principle of comparing the conditions at the terminals of the protected line, the relays
being connected to operate if the comparison indicates a fault in the line. The information
necessary for this comparison is transmitted between terminals over a pilot-wire circuit,
hence the designation of this type of relaying. Because, like all differential schemes, it is
completely and inherently balanced within itself and completely selective, the pilot-wire
relay scheme does not provide protection for faults of the adjacent station bus or beyond it.
The new static wire pilot differential relay [B30] operates on the circulating current principle.
It offers an ideal form of cable differential protection for industrial plants. The pilot wire cir-
cuit may be a set of secondary conductors interconnecting the two relay terminals, a dedi-
cated telephone line circuit, or a fiber-optic circuit. The latter is used where freedom from
induced voltages, displaced potentials, or telephone interference is important for maximum
reliability.

5.3.10 Voltage relays

Voltage relays that function at predetermined values of voltage may be overvoltage, under-
voltage, a combination of both, voltage unbalance (comparing two sources of voltage),
reverse phase voltage, or excess negative- sequence voltage induced by single phasing of a
three-phase system. Plunger-type, induction-type, or solid-state-type relays are available.
Adjustments of pickup or dropout voltage and operation timing are usually provided in these
relays. Plunger-type relays are usually instantaneous in operation, although bellows, dash
pots, or other delay means can be provided. The time-delay feature is often required in order
that transient voltage disturbances will not cause nuisance relay operation. Some typical volt-
age relay applications are as follows:

a) Over- or under voltage relays

1 ) Capacitor switching control

2) AC and dc overvoltage protection for generators

3) Automatic transfer of power supplies

4) Load shedding on undervoltage

5) Undervoltage protection for motors

b) Voltage balance relays. Blocking the operation of a voltage-controlled current relay
when a potential transformer fuse blows.

c) Reverse-phase voltage relays

1) Detection of reverse-phase connections of interconnecting circuits, transform-
ers, motors, or generators

2) Prevention of any attempt to start a motor with one phase of the system open

d) Negative-sequence voltage relays. Detection of single phasing, damaging phase volt-
age unbalance, and reversal of phase rotation of supply for protection of rotating
equipment.

5.3.11 Distance relays, Device 21 [B23]

Distance relays comprise a family of relays that measure voltage and current, and the ratio is
expressed in terms of impedance. Typically, this impedance is an electrical measure of the
distance along a transmission line from the relay location to a fault. The impedance can also

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represent the equivalent impedance of a generator or large synchronous motor when a dis-
tance relay is used for loss-of-held protection.

The measuring element is usually instantaneous in action, with time delay provided by a
timer element so that the delay, after operation of a given measuring element, is constant. In a
typical transmission-line application, three measuring elements are provided. The first
operates only for faults within the primary protection zone of the line and trips the circuit
breaker without intentional time delay. The second element operates on faults not only in the
primary protection zone, but also in one adjacent or backup protection zone, and initiates
tripping after a short time delay. The third element is set to include a more distant zone and to
trip after a longer time delay. These relays have their greatest usefulness in applications
where selective stepped operation of circuit breakers in series is essential, where changes in
operating conditions cause wide variations in magnitudes of fault current, and where load
currents may be large enough, in comparison with fault currents, to make overcurrent relay-
ing undesirable.

The three main types of distance relay and their usual applications are as follows:

a) Impedance-type. Phase-fault relaying for moderate-length lines.

b) Mho-type. Phase-fault relaying for long lines or where severe synchronizing power
surges may occur. Generator or large synchronous motor loss-of-held relaying [B79],

c) Reactance-type. Ground-fault relaying and phase-fault relaying on very short lines
and lines of such physical design that high values of fault arc resistance are expected
to occur and affect relay reach, and on systems where severe synchronizing power
surges are not a factor.

5.3.12 Phase-sequence or reverse-phase relays, Device 47

Reversal of the phase rotation of a motor may result in costly damage to machines, long shut-
down, and lost production. Important motors are frequently equipped with phase-sequence or
reverse-phase relay protection. If this relay is connected to a suitable potential source, it will
close its contacts whenever the phase rotation is in the opposite direction. It also can be made
sensitive to unbalanced voltage or under/overvoltage conditions (see 5.3.10).

5.3.13 Volts per hertz overexcitation relay, Device 24

Modern generator and transformer designs are optimized at 60 Hz to reduce materials within
equipment. With less material over which to distribute flux, higher flux densities exist causing
greater sensitivity to the added flux and resulting thermal loading due to the overexcitation.
Overexcitation occurs when the ratio of voltage to frequency, volts per hertz, is excessive due
to generator startup, shutdown, or load rejection. Though excitation systems generally
include circuits to prevent overexcitation, it is common practice to provide a separate relay to
protect the generator and associated transformers during manual control or in the event of
excitation system failure.

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5.3.14 Frequency relays, Device 81

Frequency relays sense under- or over-frequency conditions during system disturbances.
Most frequency relays have provision for adjustment of operating frequency and voltage. The
speed of operation depends on the deviation of the actual frequency from the relay setting.
Some frequency relays operate if the frequency deviates from the set value. Others are actu-
ated by the rate at which the frequency is changing. The usual application of this type of relay
is to selectively drop system load based on the frequency decrement in order to restore nor-
mal system stability.

5.3.1 5 Temperature-sensitive relays, Device 49

Temperature-sensitive relays usually operate in conjunction with temperature-detecting
devices, such as resistance temperature detectors or thermocouples located in the equipment
to be protected, and are used for protection against overheating of large motors (above
1500 hp), generator stator windings, and large transformer windings.

For generators and large motors, several temperature detectors are usually embedded in the
stator windings, and the hottest (by test) reading detector is connected into the temperature
relay bridge circuit. The bridge circuit is balanced at this temperature, and an increase in
winding temperature will increase the resistance of the detector, unbalance the bridge circuit,
and cause relay operation. Transformer temperature relays operate in a similar manner from
detecting devices set in winding hot spot areas. Some relays are provided with a 10 °C differ-
ential feature that will prevent re-energizing of the equipment until the winding temperature
has dropped 10 °C.

5.3.16 Pressure-sensitive relays

Pressure-sensitive relays used in power systems respond either to the rate of rise of gas pres-
sure (sudden pressure relay) or to a slow accumulation of gas (gas detector relay), or a combi-
nation of both. Such relays are valuable supplements to differential or other forms of relaying
on power, regulating, and rectifier transformers.

A sudden rise in the gas pressure above the liquid-insulating medium in a liquid-filled trans-
former indicates that a major internal fault has occurred. The sudden-pressure relay will
respond quickly to this condition and isolate the faulted transformer. Slow accumulation of
gas (in conservator tank-type transformers) indicates the presence of a minor fault, such as
loose contacts, grounded parts, short-circuited turns, leakage of air into the tank, etc. The gas-
detector relay will respond to this condition and either sound an alarm or isolate the faulted
transformer.

5.3.17 Replica-type temperature relays

Thermally activated relays respond to heat generated by current flow in excess of a certain
predetermined value. The input to the relay is normally the output of the current transformer
whose ratio should be carefully selected to match the available relay ratings. Many varied
types are available, the most common being the bimetal strip and the melting alloy types. The

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relay should be checked for variations in operating characteristics as a function of ambient
temperature.

Since the operating characteristics of this thermal replica-type relay closely match general-
purpose motor heating curves in the light and medium overload areas, they are used almost
exclusively for overload protection of motors up to 1500 hp.

5.3.18 Auxiliary relays

Auxiliary relays are used in protection schemes whenever a protective device cannot in itself
provide all the functions necessary for satisfactory fault isolation. This type of relay is avail-
able with a wide range of coil ratings, contact arrangements, and tripping functions, each
suited for a particular application. Some of the most common applications of auxiliary relays
are circuit-breaker lockout, circuit-breaker latching, targeting, multiplication of contacts, tim-
ing, circuit supervision, and alarming.

5.3.19 Direct-acting trip devices for low-voltage power circuit breakers

5.3.19.1 Electromechanical trip devices

Low-voltage power circuit breakers were for many years equipped with electromechanical
series trip-devices as the basic form of protection. State-of-the-art technology using solid-
state devices has replaced electromechanical trip devices on low-voltage breakers; however,
these older devices may still be available on replacement breakers. The electromechanical
series trip is of the moving armature type, using a heavy copper coil carrying the full load
current to provide the magnetizing force. Overload protection is provided by a dashpot
restraining the movement of the armature. Short-circuit protection is provided when the mag-
netic force suddenly overcomes a separate restraint spring. A separate adjustable unit is
required for each trip rating.

Several combinations of adjustable long-time, short-time, and instantaneous overcurrent trip
characteristics are available. These units do have some inherent disadvantages. The trip point
will vary depending upon age and severity of duty, and the devices have a limited calibration
range. Because the trip characteristic curve of electromechanical devices has a very inverse
shape with a broad tolerance band (figure 5-12), selective coordination of tripping with other
devices is difficult.

5.3.19.2 Solid-state trip devices

In contrast to electromechanical devices, solid-state trip devices operate from a low-current
signal generated by current sensors or current transformers in each phase. Signals from the
sensors are fed into the solid-state trip unit, which evaluates the magnitude of the incoming
signal with respect to its calibration setpoints and acts to trip the circuit breaker if preset val-
ues are exceeded. As with electromechanical trip devices, several overcurrent trip characteris-
tics are available. In most instances, the trip ratings of solid-state devices are determined by
switch settings or ratings plugs; thus, separate trip units are not required for each trip rating.

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RATIO OF ACTUAL CURRENT TO CIRCUIT BREAKER RATING

Figure 5-12— Typical time-current plot for electromechanical trip devices

In addition to phase protection, the solid-state trip device is available with integral ground-
fault trip protection.

Solid-state trip devices are more accessible on the circuit breaker than are electromechanical
trip devices and are much easier to calibrate since low values of currents can be fed through
the device to simulate the effect of an actual fault-current signal. Special care or provisions
are sometimes necessary to guarantee predictable operation when applying solid-state trip
devices to loads having other than the pure sinusoidal current wave shapes. Vibration, tem-
perature, altitude, and duty cycle have virtually no effect on the calibration of solid-state trip

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devices. Thus, excellent reliability is generally possible. The most important advantage of
solid-state trip devices is the shape of the trip characteristic curve, which is essentially a
straight line throughout its working portion (figure 5-13). These devices have a very narrow
and predictable tolerance, which enables several such devices to be selectively coordinated.

Figure 5-13— Typical time-current plot for solid-state trip devices

5.3.20 Fuses [B61]

The term fuse is defined by IEEE Std 100-1992 [B55] as “an overcurrent protective device
with a circuit opening fusible part that is heated and severed by the passage of overcurrent
through it.” From this definition it can be seen that a fuse is intended to be responsive to cur-
rent and provide protection against system overcurrent conditions. Modern fuses suitable for
the range of voltages encountered on industrial power systems fall into two general catego-
ries: power fuses (over 600 V) and low-voltage fuses (under 600 V). Fuses have achieved
widespread use on such systems because of their simplicity, economy, fast response charac-
teristics, and freedom from maintenance.

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5.3.20.1 Power fuses (over 600 V)

Power fuses rated over 600 V are of four types: the distribution fuse-cutout type, the current-
limiting type, the solid-material type, or the electronic type. Most fuses are available in
designs that comply with E rating or R rating requirements, as defined in ANSI C37. 46-1981
[B6J, or K rating requirements, as defined in ANSI C37.42-1989 [B5]. Electronic fuses are
very versatile power fuses and operate at a specific minimum pickup fault current which is
selectable based on coordination requirements, rather than within E or K rating requirements.

5.3.20.1.1 Distribution fuse cutouts

This type of fuse is generally used in distribution system cutouts or disconnect switches. To
interrupt a fault current, an arc-confining tube with a de-ionizing fiber liner and fusible ele-
ment is employed. Arc interruption is accomplished by the rapid production of pressurized
gases within the fuse tube, which extinguishes the arc by expulsion from the open end or ends
of the fuse.

Enclosed, open, and open-link types of expulsion fuses are available for use as cutouts.
Enclosed cutouts have terminals, fuse clips, and fuse holders mounted completely within an
insulating enclosure. Open cutouts have these parts completely exposed. Open-link cutouts
have no integral fuseholders, and the arc-confining tube is incorporated as part of the fuse
link.

Since gases are released rapidly during the interruption process, the operation of expulsion-
type fuses is comparatively noisy. They are rarely, if ever, applied in an enclosure because of
the special care required to vent any ionized gases that might be released and that would
cause a flashover between internal live parts. Fuse cutouts and disconnect switches are used
indoors for the protection of industrial plant distribution systems and provide fault and over-
load protection of distribution feeder circuits, transformers, and capacitor-bank fault protec-
tion. They have an inverse time-current characteristic that is compatible with standard
overcurrent relays.

5.3.20.1.2 Current-limiting power fuses

This type of fuse is designed so that the melting of the fuse element introduces a high arc
resistance into the circuit in advance of the prospective peak current of the first half-cycle. If
the fault-current magnitude is sufficiently high, the arc voltage that rapidly escalates will
forcibly limit the current to a peak value that is lower than the prospective peak. This reduced
peak value is referred to as the peak let-through current, which may be a small fraction of the
peak current that would flow without the current-limiting action of the fuse. If the fault-cur-
rent magnitude is not sufficiently high, current limitation will not be achieved.

A general-purpose current-limiting fuse is defined as a fuse capable of interrupting all cur-
rents from the rated maximum interrupting current down to the current that causes melting of
the fusible element in one hour. This type of fuse is not intended to provide protection against
low-magnitude overload currents, since it can reliably interrupt only currents above approxi-
mately twice its continuous rating for E-rated fuses and usually above approximately three

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times its continuous rating for non-E-rated fuses. Typical applications are for the protection
of power transformers, potential transformers, and feeder circuits. A typical time-current
characteristic for this type of fuse is shown in figure 5- 14(a). Note that while fuses’ nearly
straight and vertical characteristic makes selective coordination with other fuses easy, they
may be more difficult to coordinate with overcurrent relays.

Current-limiting fuses of the R-rated type are most commonly applied in motor starters utiliz-
ing contactors that are not capable of interrupting high magnitudes of fault current. The “R”
designation is not related to the continuous-current rating, although each fuse does have a
permissible continuous current that is published by the manufacturer. The R number is 1/100
of the amperes required to open the fuse in about 20 s. The fuse provides the necessary short-
circuit protection, but must be used in combination with an overload protective device to
sense lower values of overcurrent that are within the capability of the contractor. Fuses of this
type are generally designed to interrupt currents that melt the fuse element in less than 100 s,
but the fuse is not self-protecting on lower overcurrents.

The current-forcing action of current-limiting fuses during interruption produces transient
overvoltage on the system, which may require the application of suitable surge-protective
apparatus for proper control. The duty imposed on surge arresters can be relatively severe and
should be carefully considered in selecting the equipment to be applied [B33].

Current-limiting power fuses are available in various frequency, voltage, continuous-current-
carrying capacity, and interrupting ratings that conform to the requirements of IEEE Std
C37.40-1981 [B39], IEEE Std C37.41-1988 |B40], ANSI C37.46-1981 [B6J, and ANSI
C37.47-1981 [B7],

5.3.20.1.3 Solid-material power fuses

This type of fuse utilizes densely molded solid boric-acid powder as the lining for the inter-
rupting chamber. This solid-material lining liberates incombustible, highly de-ionized steam
when subjected to the arc established by melting of the fusible element. Solid-material power
fuses have higher interrupting capacities than fiber-lined power fuses of identical physical
dimensions, produce less noise, need less clearance in the path of the exhaust gases and,
importantly, can be applied with normal electrical clearance indoors or in enclosures when
equipped with exhaust control devices. Exhaust control devices provide silent operation and
contain all arc-interruption products. Indoor mountings with solid-material-type power fuses
can be furnished with an integral hookstick-operated load-current interrupting device, thus
providing single-pole live switching in addition to fault interrupting functions provided by
the fuse. Many of these fuses also include an indicator that shows when the fuse has operated.
These advantages, plus their availability in a wide range of current and interrupting ratings
and time-current characteristics that conform to all applicable standards, have led to the wide
use of solid-material power fuses in utility, industrial, and commercial power-distribution
systems.

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5.3.20.1.4 Electronic power fuses

Recently, another type of power fuse, the electronic fuse, has been introduced. This latest
technological development combines many of the features and benefits of power fuses and
relays. Electronic fuses generally consist of two separate components: an electronic control
module that provides the time-current characteristics and the energy to initiate tripping, and
an interrupting module that interrupts current when an overcurrent occurs. These two mod-
ules, when joined together, are held in a suitable holder that fits in a mounting. A current
transformer located within the control module powers the logic circuits employed in the con-
trol module which may have instantaneous tripping characteristics, time-delay tripping char-
acteristics, or both. These two circuits may be used alone or in combination to provide a
variety of time-current characteristics. When an overcurrent occurs, the control module trig-
gers a high-speed gas generator that separates the main current path in the interrupting mod-
ule, transferring the current into the current-interrupting ribbon elements, which then melts
and burns back. Only the interrupting module is replaced following fuse operation.

Electronic power fuses are suitable for service-entrance protection and coordination of indus-
trial and commercial distribution circuits because these fuses have high current-carrying
capability and incorporate unique time-current characteristics designed for superior coordi-
nation with source-side overcurrent relays and load-side feeder fuses. They are ideally suited
for load-feeder protection and coordination in industrial, commercial, and utility substations
because of their high continuous and interrupting ratings. Specific time-current characteris-
tics are available for primary-side protection of transformers and for application at the head
of an underground loop system to provide backup protection for pad-mounted transformers
containing fuses with a limited interrupting capability. Indoor mountings with electronic
fuses can be furnished with an integral hookstick-operated load-current interrupting device,
thus providing for single-pole live switching in addition to the fault interrupting functions
provided by the fuse.

Some electronic fuses also include indicators that make it easy to determine which fuse has
operated. A typical time-current characteristic curve for this type of fuse is shown in
figure 5- 14(b). Because this fuse is available with many unique time-current characteristics,
it can easily coordinate both with line-side overcurrent relays and load-side power fuses.

5.3.20.2 Low-voltage fuses (600 V and below)

These fuses are covered by the following standards: NEMA FU 1-1986 [B70] and by the
ANSI/UL 1 98 series [B 14] -[B 1 9] .

Plug fuses are of three basic types, all rated 125 V or less to ground and up to 30 A maximum
with an interrupting rating of 10 000 A. The three types are as follows:

a) Edison base with no time delay in which all ratings are interchangeable;

b) Edison base with a time delay and interchangeable ratings;

c) Type S base, available in three noninterchangeable current ranges; 0-15 A, 16-20 A,
and 21-30 A.

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30 A

FUSE

-Lva

CURRENT IN AMPERES X 10

20 30 50 100 200 300 500 1000 2000 3000 5000 10 000

1 — I 1 1 1 — I 1 1 1 — I 1 1 iooo

TYPICAL 14.4 kV EXPULSION-TYPE
' FUSE USING SOLID MATERIAL AS ~
THE ARC EXTINGUISHING MEDIUM
INTERRUPTING RATING (VENTED)

20 kA, SYMMETRICAL RMS

■ MINIMUM MELT CHARACTERISTIC -
; TOTAL CLEARING CHARACTERISTIC,

TYPICAL 14.4 kV CURRENT-LIMITING
FUSE USING SILICA SAND AS THE
ARC EXTINGUISHING MEDIUM
INTERRUPTING RATING 50 kA,
SYMMETRICAL RMS

MINIMUM MELT CHARACTERISTIC
TOTAL CLEARING CHARACTERISTIC

■■■I

20 30 50 100 200 300 500 1000 2000 3000 5000 10 000

CURRENT IN AMPERES X 10

Figure 5-14 (a)— Time-current characteristic curves showing
the difference between solid-material expulsion-type
and current-limiting-type power fuses

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10 100 1 000 10 000 100 00
CURRENT, IN AMPERES

Figure 5-14 (b)— Time-current characteristic curves showing
the ability of electronic fuses in a service-entrance application
to coordinate with the upstream utility circuit breaker and
downstream feeder fuses and transformer primary fuses

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These last two types normally have a time-delay characteristic of at least 12 s at 200% of
their rating, although time-delay plug fuses are no longer required by the NEC [BIO],

Cartridge fuses may be either renewable or nonrenewable. Nonrenewable fuses are factory
assembled and must be replaced after operating. Renewable fuses can be disassembled and
the fusible element replaced. Renewable elements are usually designed to give a greater time
delay than ordinary nonrenewable fuses, and in some designs the delay on moderate overcur-
rents is considerable. The renewable-type fuse is not available in ratings above 10 000 A.

a) Noncurrent-limiting fuses (Class H). These fuses interrupt overcurrents up to
10 000 A but do not limit the current that flows in the circuit to the same extent as do
recognized current-limiting fuses. As a general rule, they should only be applied in
circuits where the maximum available fault current is 10 000 A and the protected
equipment is fully rated to withstand the peak available fault current associated with
this fault duty, unless such fuses are specifically applied as part of an equipment com-
bination that has been type-tested and designed for use at higher available fault cur-
rent levels.

b) Current-limiting fuses. Current-limiting fuses are intended for use in circuits where
available short-circuit current is beyond the withstand capability of downstream
equipment or the interrupting rating of ordinary fuses or standard circuit breakers. An
alternating current-limiting fuse is a fuse that safely interrupts all available currents
within its interrupting rating and, within its current-limiting range, limits the clearing
time at rated voltage to an interval equal to or less than the first major or symmetrical
current loop duration, and limits peak let-through current to a value less than the peak
current that would be possible with the fuse replaced with a solid conductor of the
same impedance. A current-limiting fuse, therefore, places a definite ceiling on the
peak let-through current and thermal energy, providing equipment protection against
damage from excessive magnetic stresses and thermal energy (see applicable ANSI/
UL 198 standards for maximum let-through limits).

These fuses are widely used in motor starters, fused circuit breakers, fused switches
of motors and feeder circuits for protection of busway and cable, and many other
applications.

c) Let-through considerations. Figure 5-15 illustrates typical current-limiting fuse oper-
ating characteristics during a high-fault-current interruption. In applications involv-
ing high available fault currents, the operating characteristics of the current-limiting
fuse limit the actual current that is allowed to flow through the circuit to a level sub-
stantially less than the prospective maximum. The peak let-through current of a cur-
rent-limiting fuse is the instantaneous peak value of current through the fuse during
fuse opening. The let-through I~t of a fuse is a measure of the thermal energy devel-
oped throughout the entire circuit during clearing of the fault. Both values are impor-
tant in evaluating fuse performance and can be determined from peak let-through and
I~t curves supplied by the fuse manufacturer. A let-through current value consider-
ably less than the available fault current will greatly reduce the magnetic stresses
(which are proportional to the square of the current) and thus reduce fault damage in
protected equipment. In some cases it becomes possible to use components (that is,
motor starters, disconnect switches, circuit breakers, and bus duct) in the system that

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(b) Fault occurring at zero voltage

a — Melting Time
b — Arcing Time
c — Total Clearing Time

Figure 5-15— Typical current-limitation characteristics
showing peak let-through and maximum prospective fault
current as a function of the time of fault occurrence
(100 kA available rms symmetrical current)

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have fault capabilities much less than the maximum fault current available. The low
peak let-through current and fit levels can be achieved with current-limiting fuses
because of their extremely fast (often less than one quarter-cycle) speed of response
when subjected to high-fault current. The speed of response is governed by fuse
design. For highest speed, silver links with special configurations surrounded by
quartz sand are used.

Peak let-through current values alone cannot determine the comparable effectiveness
of current-limiting fuses. The product of the total clearing time and the effective
value of the let-through current squared I~t , or thermal energy, should be considered
as well.

The melting It of a fuse does not vary with voltage. However, arcing It is voltage-
dependent and the arcing I~t at 480 V, for example, will not be as great as that at
600 V.

d) Dual-element or time-delay fuses. A dual-element fuse has current-responsive ele-
ments of two different fusing characteristics in series in a single cartridge. The fuse is
one-time in operation, and the fast-acting element responds to overcurrents that are in
the short-circuit range. The time-delay element permits short-duration overloads, but
melts if these overloads are sustained. The most important application for these fuses
is motor and transformer protection. They do not open on motor starting or trans-
former magnetizing inrush currents, but still protect the motor and branch circuits
from damage by sustained overloads.

e) Fuse standards (cartridge). Cartridge fuses differ in dimensions according to voltage
and current ratings. They have ferrule contacts in ratings of 60 A or less and knife-
blade contacts in larger ratings. Cartridge fuses of varying types and characteristics
have been classified by the ANSI/UL 198 series [B 14]— [B 19J into the following
classes:

1) Miscellaneous cartridge fuses. These fuses are not intended for use in branch
circuits but rather for use in control circuits, special electronic or automotive
equipment, etc. To be industry-listed they must not be manufactured in the same
dimensions as UL classes G, H, J, K, CC, T, or L. They have ratings of 125, 250,
300, 500, and 600 V, and are applied in accordance with the NEC [B10].

2) Class H fuses. These fuses may be renewable or nonrenewable and are generally
of copper or zinc link construction. They are rated and sized up to 600 A at
either 250 V or less or 600 V or less. They may or may not be of dual-element
construction, but if labeled as time-delay they must have a minimum delay of
10 s at 500% of rating except that a 250 V fuse rated 30 A or less must have a
minimum delay of 8 s. These fuses have an interrupting rating of 10 000 A and
must only be used where fault currents do not exceed this magnitude. Class H
fuses are often referred to as NEC fuses, and the nonrenewable class H fuse is
sometimes referred to as a one-time fuse, although this may describe other fuse
types as well. Renewable fuses are losing popularity because of their limited
interrupting ability and the dangers of double-linking or insecurely fastening
renewal links.

3) Class K high-interrupting-rating fuses . These fuses are manufactured in identi-
cal physical sizes as class H fuses, with which they are interchangeable and.

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therefore, cannot be labeled with the words current-limiting. However, they
have been tested at various high available fault-current levels up to their maxi-
mum labeled ratings, which may be either 50 000, 100 000, or 200 000 A rms.
Thus, fuses in this class are referred to as high-interrupting-rating fuses. Class K
fuses must meet specified maximum values of instantaneous peak let-through
currents and fit energy let-through maximum values for each physical case size.
Each fuse label bears the ac interrupting rating, the class and subclass and, if the
fuse meets the time-delay requirement of at least 10 s (or 8 s for a 250 V fuse
rated 30 A or less) at 500% rating, it may be labeled as time-delay or with the
letter D. According to ANSI/UL 198D-1987 [B16], class K fuses are available in
three distinct subclasses identified as class Kl, class K5, and class K9. Class K1
fuses have the lowest maximum values for peak let-through currents and fit ,
class K9 have the highest maximum values, and the class K5 values are between
the Kl and K9 values. Most earlier class K9 types have been modified and now
have class K5 characteristics.

4) Class R current-limiting fuses. These fuses are a nonrenewable cartridge-type
current-limiting fuse also manufactured to class H dimensional standards and
have a 200 000 A rms symmetrical interrupting rating. The R designator signi-
fies the fact that the fuse is built with a rejection feature that consists of grooves
or notches provided in either the fuse ferrule or blade, depending on the size
involved. Equipment rated and approved only for use with fuses having the cur-
rent-limiting characteristics of class R fuses is then provided with fuse attach-
ment hardware that will only permit the installation of the notched fuses. Since
this rejection feature eliminates the possibility of interchanging a current-limit-
ing fuse with a noncurrent-limiting fuse, the class R fuses are labeled with the
words, current-limiting. These class R fuses are available in either the single- or
dual-element construction. The fuses are available in two subclasses identified
as RK1 and RK5, which denote the fact that the fuses have let- through charac-
teristics corresponding to class Kl and K5 fuses, respectively. Since equipment
that is approved for class R service is always rated to withstand the higher let-
through current of RK5 fuses, either the RK1 or the RK5 fuse can be safely
applied. Some fuses in this rating class listed with interrupting ratings up to
300 000 A are designated as special purpose fuses.

5) Class J current-limiting fuses. These fuses are manufactured in ratings up to
600 A and in specified dimensions per ANSI/UL 198C-1986 [B15], which are
non-interchangeable with class H and class K fuses. They are labeled as current-
limiting. There is no 250 V or less rating; all are labeled 600 V or less and may
be used only in fuseholders of suitable class J dimensions. Each case size has
specified maximum values of peak let-through current values and maximum
thermal (fit) values. Fuses having a time-delay characteristic are available in
class J dimensional sizes. UL-listed class J fuses with time delay are available
from several manufacturers. Class J fuses have a 200 000 A rms interrupting rat-
ing. Some fuses in this rating class with interrupting ratings up to 300 000 A are
designated as special purpose fuses.

6) Class L current-limiting fuses. These are the only UL-labeled fuses available
with current ratings in excess of 600 A. Per ANSI/UL 198C-1986 [B15], their

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ratings range from 601 to 6000 A rms, all at 600 V or less. There is no 250 V
size. Class L fuses have an interrupting rating of 200 000 A rms. Like class J
fuses, each case size or mounting dimension (mounting holes drilled in the
blades) has a maximum allowable peak let-through current and fit value. Some
fuses in this rating class listed with interrupting ratings up to 300 000 A are des-
ignated as special purpose fuses.

A fuse should be selected for voltage, current-carrying capacity, and interrupting
rating. When fuses must be coordinated with other fuses or circuit breakers, the
time-current characteristic curves, peak let-through curves, and I t curves may be
useful. The load characteristics will dictate the time-delay performance required
of the fuse. If fuses are applied in series in a circuit, it is essential for selectivity
during short circuits to verify that the clearing I~t of the load-side fuse during a

fault will be less than the melting I t of the line-side fuse. Fuse manufacturers
publish fuse-ratio tables that provide listings of fuses that are known to operate
selectively. Use of these tables permits coordination without the need for detailed
analysis, provided the fuses being applied are all of the same manufacturer.

5.3.20.3 Fuse-selection considerations

For each fuse classification rated 600 V and below, the corresponding UL standards specify
the following design features that are particularly important to fuse application: current rat-
ing, voltage rating, frequency rating, interrupting rating, maximum peak let-through current,
and maximum clearing thermal energy, I t. Standards also specify maximum opening times
at certain overload values, such as 135 and 200% of rating, and for time-delay qualification,
minimum opening time at a specific overload percentage. Within these parameters and from
various other overcurrent test data, manufacturers construct time-current curves. Normally
such curves are based on available rms currents 0.01 s and above, and on either the average
melting, minimum melting, or total clearing time. Caution should be exercised in the use of
such curves to be certain that equivalent characteristics are being compared.

When coordinating a line-side circuit breaker with a load-side fuse, the let-through energy of
the fuse (clearing I t) must be less than the required amount to release the circuit breaker trip
latch mechanism. This is not easily accomplished with many types of circuit breakers. Criti-
cal operation occurs in the region for currents greater than the circuit breaker instantaneous
trip device pickup for periods of time less than 0.01 s, even though a normal time-current plot
would suggest that selective performance exists. Similar problems exist when attempting to
coordinate a load-side circuit breaker with a line-side fuse. The clearing time of the circuit
breaker can often exceed the minimum melting time of the fuse. Overload coordination for
low-magnitude or moderate faults can be established with standard time-current curve over-
lays (for details, see IEEE Std 242-1986 [B57], Thus, it may be impossible to selectively
coordinate current-limiting fuses and circuit breakers at all current levels up to the maximum
short-circuit currents.

For protection of a circuit breaker with a line-side fuse during high-fault currents, UL now
series-tests and issues various combinations of fuses and circuit breakers as submitted by dif-
ferent manufacturers. These recognized combinations are preferable to manufacturers’ data
without third-party certification, where available.

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The proper selection of a fuse to protect a starter, busway, or cable circuit will generally pre-
vent their failure during a through-fault condition. It is the design engineer’s responsibility to
review the current-limiting fuse let-through current for selection of withstand ratings of
equipment that has not been tested for a specific class and maximum size of fuse. The voltage
rating of a fuse should be selected as equal to or higher than the nominal system voltage on
which it is used. A low-voltage fuse of any labeled voltage rating will always perform satis-
factorily on lower service voltages.

The current rating of a fuse should be selected so that it clears only on a fault or an overload
and not on current inrush. Ambient temperatures and types of enclosures affect fuse perfor-
mance and should be considered. Fuse manufacturers should be requested to supply correc-
tion factors for unusual ambient temperatures.

When applying a current-limiting fuse of a given voltage rating over 600 V on a circuit of a
lower voltage rating, consideration should be given to the magnitude and effect of overvolt-
ages that will be induced due to the zero current forcing action of the fuse during the interrup-
tion of high-magnitude fault currents.

5.4 Performance limitations

5.4.1 Load current and voltage wave shape

The published operating characteristics of all protective relays and trip devices are based on
an essentially pure sinusoidal wave-shape of current and voltage. Many industrial loads are of
such a nature as to produce harmonics in the system current and voltage. This condition is
aggravated by the presence of any distribution equipment in the system with nonlinear elec-
trical characteristics. As a result, it is important to understand the nature of the expected sys-
tem current and voltage as well as the effect that wave-shape distortion might have on the
protective devices being applied [B34],

5.4.2 Instrument transformers [B57], [B82]

If a protective relay is to operate predictably and reliably, it must receive information that
accurately represents conditions that exist on the power system from the circuit instrument
transformers. Since current and potential transformers become significantly nonlinear devices
under certain conditions, they may not produce an output precisely representative of power
system conditions either in wave shape or magnitude. The exact extent of any distortion is a
function of the input signal level and transformer burden (total connected impedance) as well
as the actual design (accuracy class) of the instrument transformer being applied. Potential
transformer performance characteristics are classified by IEEE Std C57. 13-1990 [B48]. This
same standard provides separate classifications for current transformers with regard to burden
capability and accuracy for both metering and relaying service. The burden and output
requirements of all instrument transformers should be carefully checked against their rating
for any relay application to verify that proper relay operation will result. In some cases where
a larger burden is encountered or the expected level of fault current is higher than that encom-
passed by the IEEE Std C57.13-1990 rating structure, it may be necessary to obtain the cur-

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rent transformer saturation curve from the manufacturer in order to analytically establish
acceptable performance.

5.5 Principles of protective relay application [B23], [B43], [B65]

Fault-protection relaying can be classified into two groups: primary relaying, which should
function first in removing faulted equipment from the system, and backup relaying, which
functions only when primary relaying fails.

To illustrate the areas of protection associated with primary relaying, figure 5-16 shows the
various areas, together with circuit breakers, that feed each electric element of the system.
Note that it is possible to disconnect any piece of faulted equipment by opening one or more
circuit breakers. For example, when a fault occurs on the incoming line Lj, the fault is within
a specific area of protection (area A) and should be cleared by the primary relays that operate
circuit breakers 1 and 2. Likewise, a fault on bus 1 is within a specific area of protection, area
B, and should be cleared by the primary relaying actuating circuit breakers 2, 3, and 4. If cir-
cuit breaker 2 fails to open and the faulted equipment remains connected to the system, the
backup protection provided by circuit breaker 1 and its relays must be depended upon to clear
the fault.

Figure 5-16 illustrates the basic principles of primary relaying in which separate areas of pro-
tection are established around each system element so that each can be isolated by a separate
interrupting device. Any equipment failure occurring within a given area will cause tripping
of all circuit breakers supplying power to that area.

To assure that all faults within a given zone will operate the relays of that zone, the current
transformers associated with that zone should be placed on the line side of each circuit
breaker so that the circuit breaker itself is a part of two adjacent zones. This is known as over-
lapping. Sometimes it is necessary to locate both sets of current transformers on the same
side of the circuit breaker. In radial circuits the consequences of this lack of overlap are
not usually very serious. For example, a fault at X on the load side of circuit breaker 3 in
figure 5-16 could be cleared by the opening of circuit breaker 3 if there were any way to
cause it to open circuit breaker 3. Since the fault is between the circuit breaker and the current
transformers, the relays of circuit breaker 3 will not see it, and circuit breaker 2 will have to
open and consequently interrupt the other load on the bus. When the current transformers are
located immediately at the load bushings of the circuit breaker, the amount of circuit exposed
to this problem is minimized. The consequences of lack of overlap become more serious in
the case of tie circuit breakers between differentially protected buses and bus feeders pro-
tected by differential or pilot- wire relaying.

In applying relays to industrial systems, safety, simplicity, reliability, maintenance, and the
degree of selectivity required should be considered. Before attempting to design a protective
relaying plan, the various elements that make up the distribution system, together with the
operating requirements, should be examined.

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UTILITY

Figure 5-16— One-line diagram illustrating zones of protection

5.5.1 Typical small-plant relay systems

One of the simplest industrial power systems consists of a single service entrance circuit
breaker and one distribution transformer stepping the utility’s primary distribution voltage
down to utilization voltage, as illustrated in figure 5-17. There would undoubtedly be several
circuits on the secondary side of the transformer, protected by either circuit breakers or com-
bination fused switches.

Protection for the feeder circuit between the incoming line and the devices on the transformer
secondary would normally consist of conventional overcurrent relays. Devices 50/51. Prefer-
ably, the relays should have the same time-current characteristics as the relays on the utility
system, so that for all values of fault current the local service entrance circuit breaker can be

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13.2 kV UTILITY SYSTEM

Figure 5-17— Typical small industrial system

programmed to trip before the utility supply line circuit breaker. The phase relays should also
have instantaneous elements. Device 50, to promptly clear high-current faults.

This simple system provides both primary and backup relay protection. For instance, a fault
on a secondary feeder should be cleared by the secondary protective device; however, if this
device should fail to trip, the primary relays will trip circuit breakerl. Where the secondary
voltage is 600 V or less, local code authorities may require a main secondary device to be
installed to protect the incoming conductors and provide back-up protection to the feeder pro-
tective devices. This simple industrial system can be expanded by tapping the primary feeder
and providing fuse protection on the primary of each distribution transformer, as shown in
figure 5-18.

This provides an additional step or area of protection over the simpler system shown in
figure 5-17. All secondary feeder faults should be cleared by the secondary overcurrent
devices as before, while faults within the transformer should now be cleared by the trans-
former primary fuses. The fuses may also act as backup protection for the faults that are not
cleared by the secondary feeder overcurrent devices. Primary feeder faults will, as before, be
cleared by circuit breaker 1 , and it, in turn, will act as backup protection for the transformer
primary fuses.

5.5.2 Protective relaying for a large industrial plant power system
[B63], [B80], [B81]

As an electric system becomes larger, the number of sequential steps of relaying also
increases, giving rise to the need for a protective relaying scheme that is inherently selective
within each zone of protection. Figure 5-19 shows the main connections of a large system.

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13.2 kV UTILITY SYSTEM

Figure 5-18— System of figure 5-17 expanded by addition of
a transformer and associated secondary circuits

5.5. 2.1 Primary protection

The relay selectivity problem is of great concern to the utilities because their 69 kV supply
lines are paralleled and their transformers are connected in parallel with the plant’s local gen-
eration. The utility company should participate in the selection of relays applied for operation
of either incoming circuit breaker in case of a disturbance in the 69 kV bus or transformers.
Due to the 69 kV bus tie, a fault in either a bus or a transformer cannot be cleared by the
opening of circuit breaker A or B alone, but will require the opening of circuit breakers A or
B as well as AB and C or D.

When 69 kV tie breaker is open and a fault occurs on utility line 1, fault current will flow
from line 2 back through the two industrial supply transformers. Three overcurrent relays
having inverse-time characteristics should be installed at circuit breaker positions A and B as
backup protection for faults that may occur on or immediately adjacent to the 69 kV buses.
The connection of these overcurrent relays (Devices 50/51), shown in figure 5-19 as being
energized from the output of two current transformers in a summation connection at the
incoming 69 kV lines and bus tie, provides the advantage of isolating only the faulted bus
section in a shorter time than would be possible if individual circuit breaker relays were used.
This is commonly called a partial differential scheme.

Three directionally controlled overcurrent relays (Device 67) should be installed for circuit
breakers C and D and connected to trip for current flow toward the respective 69 kV trans-
former. Directionally controlled overcurrent relays are ideal for interrupting this current,
since their sensitivity is not limited by the magnitude of load current in the normal or nontrip
direction.

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The next zones of protection are the 13.8 kV buses 1 and 2. Fault currents are relatively high
for any equipment failure on or near the main 13.8 kV buses. For this reason a differential
protective relay scheme (Device 87B) is recommended for each bus. Differential relaying is
instantaneous in operation and is inherently selective within itself. Without such relaying,
high-current bus faults should be cleared by proper operation of overcurrent devices on the
several sources. This usually results in long-time clearing since the overcurrent devices have
pickup and time settings determined by other than bus fault considerations. General practice
is to use separate current transformers with the same ratio and output characteristics for the
differential relay scheme. A multicontact auxiliary relay (Device 86B) is used with the dif-
ferential relays to trip all the circuit breakers connected to the bus whenever a bus fault
occurs. To realize maximum sensitivity, the time-delay ground relays (Device 5 IN) at the
69-13.8 kV source transformers are connected to the output of current transformers measur-
ing the current in the neutral connection to ground. The 87TN relay is differentially con-
nected to provide sensitive tripping on faults between the transformer secondary and the
13.8 kV main circuit breaker. Auxiliary current transformers will normally be required to
provide equal currents to the relay. Unlike the time-delay relays 51N-1 and 51N-2, this relay
does not have to be set to be selective with other downstream ground-fault relays. Selective
tripping of breakers C and D is achieved by the use of the partial differential relays scheme
(Device 51).

Superior protection for the cable tie between buses 2 and 3 is provided by pilot-wire differen-
tial relays (Device 87L). In addition to being instantaneous in operation, pilot-wire schemes
are inherently selective within themselves and require only two pilot wires if the proper
relays are used. Backup protection provided by overcurrent relays should be installed at both
ends of the tie line. Nondirectional relays can be applied at circuit breaker M, but at circuit
breaker N directional relays are more advantageous since the 10 MVA generator represents a
fault source at bus 3.

Separate current transformers are used for the pilot-wire differential relaying to provide reli-
ability and flexibility in the application of other protective devices.

The 9000 hp 13.8 kV synchronous motor is provided with a reactor- type reduced- voltage
starting arrangement using metal-clad switchgear. Overload protection is provided by a ther-
mal relay (Device 49) whose sensor is a resistance temperature detector (RTD) imbedded in
the stator windings. This relay can be used to either trip or alarm. Internal fault protection is
provided by the differential relay scheme (Device 87M). Backup fault protection and locked-
rotor protection is provided by an overcurrent relay (Device 51/50) applied in all three
phases. Undervoltage and reverse-phase rotation protection are provided by the voltage-sen-
sitive relay (Device 47) connected to the main bus potential transformers.

Ground-fault protection is provided by the instantaneous zero-sequence current relay (Device
50GS). The current-balance relay (Device 46) protects the motor against damage from exces-
sive rotor heating caused by single phasing or another unbalanced voltage condition.

The motor rotor starting winding can be damaged by excessive current due to loss of excita-
tion or suddenly applied loads, which cause the motor to pull out of step. Rotor damage could
also result from excessive time for the motor to reach synchronous speed and lock into step.

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Protective device legend for Figure 5-19

Location

Device

Description

69 kV supply lines

51/50

Summation phase and ground overcurrent pro-

51N/50N

tection for 69 kV bus and backup for trans-
former differential relaying. Trips circuit-
breakers A, AB, and C through auxiliary relay
86T.

15 MVA main trans-

51N-1

Backup ground-fault protection for transformer

formers

51N-2

secondary 13.8 kV bus and feeder circuits.
51N-1 trips tie circuit breaker CD; 51N-2
(after time interval) trips circuit breaker.

Sudden pressure relay. Trips circuit breakers A,
AB, and C through auxiliary relay 86T.

Directional phase overcurrent as backup to
transformer differential. Trips circuit breakers
A, AB, and C through auxiliary relay 86T.

87TN

Sensitive differential protection for ground
faults in transformer secondary. Trips circuit
breakers A, AB, and C through auxiliary relay
86T.

87T

Transformer differential protection. Trips cir-
cuit breakers A, AB, and C through auxiliary
relay 86T.

86T

Auxiliary trip and lockout relay.

13.8 kV

Summation phase overcurrent protection as

buses 1 and 2

backup for 13.8 kV bus and feeder faults.
Trips circuit breakers C and CD through aux-
iliary relay 51 X.

87B1

Bus differential. 87B1 trips circuit breakers C,

87B2

CD, E, F, G, and H through auxiliary relay
86B1. 87B2 trips circuit breakers D, CD, I,
J, K, L, and M through auxiliary relay 86B2.

86B1

86B2

Auxiliary trip and lockout relay.

Underfrequency protection. Initiates load shed-
ding by tripping preselected feeder circuits.

13.8 kV

51/50

Time and instantaneous phase-fault protection.

feeders E, F, G,

Trips individual feeder circuit breaker.

H, I, and J

50GS

Instantaneous ground-fault protection. Trips
individual feeder circuit breaker.

13.8 kV

Loss of excitation, incomplete sequence check-

motor control

ing and pullout protective relays. Trips cir-

circuit breakers

56PO

cuit breakers K and L.

KandL

Current balance relay for single-phase protec-
tection. Trips circuit breakers K and L.

Polyphase undervoltage and phase reversal
protection. Trips circuit breakers K and L
through auxiliary relay 86M.

Overload protection using stator resistance
temperature detector. Trips circuit breakers
K and L through auxiliary relay 86M.

50GS

Instantaneous ground-fault protection. Trips
circuit breakers K and L through auxiliary
relay 86M.

51/50

Phase overcurrent protection and locked rotor
protection. Trips circuit breakers K and L
through auxiliary relay 86M.

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Std 141-1993

Protective device legend for Figure 5-19 (continued)

Location

Device

Description

13.8 kV

87M

Motor differential protection. Trips circuit

motor control

breakers K and L through auxiliary relay

circuit breakers

86M.

K and L (cont’d)

86M

Auxiliary trip and lockout relay.

13.8 kV tie line

51GS

Sensitive ground-fault protection as backup to

circuit breaker M

pilot-wire relaying and backup for bus and
feeder ground faults at 13.8 kV bus 3. Trips
circuit breaker M.

Phase overcurrent protection as backup to
pilot-wire relaying and hackup for bus and
feeder faults at 13.8 kV buses. Trips circuit
breaker M.

87L

Line differential protection for phase and
ground faults using pilot wire. Trips circuit
breaker M.

Pilot wire monitoring relay to alarm for open,
short-circuited, or grounded pilot wire.

3.75 MVA trans-

Summation phase overcurrent protection for

former and

2.4 kV bus faults and backup protection for

2.4 kV

feeder faults. Trips circuit breakers S and ST

buses 2 and 3

through auxiliary relay 5 IX.

51N-1

Ground-fault protection for transformer sec-

51N-2

ondary and bus and backup for feeder ground
faults. 51N-1 trips tie circuit breaker ST;
51N-2 (after time interval) trips circuit
breaker S.

Sudden pressure relay on transformer. Trips cir-
cuit breakers S and H.

Directional phase overcurrent protection for
transformer faults and 13.8 kV line faults.
Trips circuit breaker S.

87TN

Sensitive differential protection for ground
faults in transformer secondary. Trips circuit
breakers S and H.

Current balance relay for single-phase protec-
tion. Trips contactor.

Polyphase undervoltage and phase sequence
protection. Trips circuit breakers S and ST
through auxiliary relay 5 IX.

Replica-type thermal overload protection. Trips
contactor.

50GS

Instantaneous ground-fault protection. Trips
contactor.

Overcurrent relay for motor locked rotor pro-
tection. Trips contactor.

1.5 MVA trans-

49/50

Replica-type thermal overload protection in-

former and

cluding instantaneous element for short-

2.4 kV bus 1

circuit protection. Trips contactor.

Phase overcurrent protection. Trips circuit
breaker R.

59N

Sensitive voltage detection of ground faults
for high-resistance grounded system. Initi-
ates alarm signal.

Single-phase undervoltage protection. Trips motor
contactor through auxiliary relay 27X.

Negative sequence voltage relay detects single phas-
ing of source. De-energizes undervoltage relay 27.

231

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Protective device legend for Figure 5-19 (continued)

Location

Device

Description

13.8 kV tie line,

Directional phase overcurrent protection as

circuit breaker

backup to pilot wire and backup for bus and

N at 13.8 kV

feeder faults at 13.8 kV buses. Trips circuit

bus 3

breaker N.

87L

Line differential protection for phase and
ground faults using pilot wire. Trips circuit
breaker N.

Pilot-wire monitoring relay to initiate alarm for
open, short-circuited, or grounded pilot wire.

51G

Sensitive ground-fault protection as backup to
pilot-wire relaying and backup for bus and
feeder faults at 13.8 kV buses. Trips circuit
breaker N.

13.8 kV

87B

Bus differential. Trips circuit breakers N, 0, P,

bus 3

and Q through auxiliary relay 86B.

86B

Auxiliary trip and lockout relay.

10 MV A

Reverse power or antimotoring protection.

generator

Trips circuit breaker O.

Loss of excitation protection. Alarm and sub-
sequent trip of circuit breaker 0.

Negative-sequence overcurrent protection for
generator due to external unbalanced fault.
Trips circuit breaker 0.

51V

Backup overcurrent protection for external
three-phase faults. Trips circuit breaker O.

51NG

Ground-fault protection for generator and
backup for differential relays and feeder
ground relays. Trips circuit breaker O and
field circuit breaker through 86G.

87G

Generator differential protection. Trips circuit
breaker O and field circuit breaker through
86G.

86G

Auxiliary trip and lockout relay.

2.5 MVA trans-

Polyphase undervoltage and phase sequence

former and

protection. Trips circuit breaker P.

motor at 13.8 kV

Temperature overload protection using stator

bus 3

resistance temperature detectors. Initiates
alarm.

49/50

Replica-type thermal overload protection in-
cluding instantaneous element for short-
circuit protection. Trips circuit breaker P.

50GS

Instantaneous ground-fault protection for 13.8
kV transformer primary. Trips circuit breaker
P.

Phase overcurrent and locked rotor protection.
Trips circuit breaker P.

51/50

Sudden pressure relay, transformer mounted.
Trips circuit breaker P.

87M

Motor differential relay. Trips circuit breaker P
through auxiliary relay 86M.

86M

Auxiliary trip and lockout relay.

1.0 MVA trans-

50GS

Instantaneous ground-fault protection. Trips

former at 13.8 kV

circuit breaker Q.

bus 3

51/50

Time and instantaneous phase-fault protection.
Trips circuit breaker Q.

480 V trans-

Directional phase overcurrent protection for

former secondary

transformer faults and 13.8 kV line faults.

circuit breakers

Trips 480 V circuit breaker.

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To protect against damage from these causes, loss of excitation (Device 40), pull-out (Device
56PO), and incomplete sequence (Device 48) relays should be provided. Multifunction motor
protection relays, (Device 11) which combine many of the above functions, e.g.. Device 49,
50LR, 50GS, 46, 48, in a single enclosure may be used. These are microprocessor-based
devices that provide sensitive levels of protection and are easily programmable to meet the
characteristics of the motor.

The 10 MVA generator connected to bus 3 is protected against internal faults by a percentage
differential relay (Device 87G) and against ground faults by the overcurrent relay in the gen-
erator neutral (Device 51NG) where the current is limited by the 400 A neutral grounding
resistor. Loss of excitation protection is provided by Device 40, and negative phase sequence
protection caused by unbalanced loading or unbalanced fault conditions is provided by
Device 46. The generator must also be protected from being driven as a motor (anti-
motoring) when the prime mover can be damaged by such operation using a reverse power
relay. Device 32. Backup overcurrent protection should be capable of detecting an external
fault condition that corresponds to the minimum level of generator contribution with fixed
excitation. This can be accomplished by three voltage-restraint or voltage-controlled overcur-
rent relays. Device 51V [ B57] .

It is good practice for transformers of the size shown on the incoming service, where a circuit
breaker is used on both the primary and secondary sides, to install percentage differential
relays and inverse characteristic overcurrent relays for backup protection. To prevent opera-
tion of the differential relays on magnetizing inrush current when energizing the transformer,
the large proportion of currents at harmonic multiples of the line frequency contained in the
magnetizing inrush current are filtered out and passed through the restraint winding so that
the current unbalance required to trip is made much greater during the excitation transient
than during normal operation.

5.5.2.2 Medium-voltage protection

The medium-voltage (2.4 kV) substations shown in figure 5-19 are designed primarily for the
purpose of serving the medium- and large-size motors. Buses 2 and 3 fed by the 3750 kVA
transformers are connected together by a normally closed tie circuit breaker, which is relayed
in combination with each main circuit breaker by means of a partial differential or totalizing
relaying scheme (Device 51). The current transformers are connected with the proper polarity
so that the relay sees only the total current into its bus zone and does not see any current that
circulates into a bus zone through either main and leaves through the tie. The relay backs up
the feeder circuit breaker relaying connected to its respective bus or operates on bus faults to
trip the tie and appropriate main circuit breakers simultaneously, thereby saving one step of
relaying time over what is required when the tie and main circuit breakers are operated by
separate relays. One possible disadvantage to this scheme occurs when a directional relay or
main circuit breaker malfunctions for a transformer fault or when a bus feeder circuit breaker
fails to properly clear a downstream fault. The next device in the system that can clear is the
opposite primary feeder circuit breaker. If this occurs, a total loss of service to the substation
will result. As a result, additional overcurrent relays (Device 51) are sometimes added to the
tie circuit breaker on systems where the possibility of this occurrence cannot be tolerated,
although they are not shown on the system in figure 5-19. These relays can be set so as not to

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extend any other relay operating time, while providing the necessary backup protection to
afford proper circuit isolation for faults upstream from either main circuit breaker.

The source ground relaying for the double-ended 2.4 kV primary unit substation is similar to
that described for the 13.8 kV transformer secondary. The single-ended 1500 kVA 2.4 kV pri-
mary unit substation on busl illustrates a method for high-resistance grounding utilizing an
isolation transformer in the neutral circuit. This scheme limits the magnitude of ground cur-
rent to a safe level, while permitting the use of a lower voltage rated resistor stack. The
remainder of the 2.4 kV relaying shown in figure 5-19 is, in one form or another, provided for
protection of the motor loads.

The application of a combination motor and transformer as shown connected to the 13.8 kV
bus 3 is referred to as the unit method. This is done to take advantage of the lower cost of the
motor and the transformer at 2.4 kV, as compared to the motor alone at 13.8 kV. Motor inter-
nal fault protection is provided by instantaneous overcurrent relays, arranged to provide dif-
ferential protection (Device 87M), by the use of zero-sequence (doughnut-type) current
transformers located either at the motor terminals or, preferably, in the starter. The latter cur-
rent transformer location will also afford protection to the cable feeder. Three current trans-
formers and three relays are applied in this form of differential protection. Thermal overload
protection is provided by Device 49 using an RTD as the temperature sensor. Surge protec-
tion is provided by the surge arrester and capacitor located at the motor terminals, while und-
ervoltage and reverse-phase rotation protection is provided by Device 47 connected to the bus
potential transformers. The sudden pressure relay (Device 63) is used for detection of trans-
former internal faults. Branch circuit phase and ground-fault protection is provided by
Devices 51/50 and 50GS, respectively.

The 500 hp induction motor served from the 2.4 kV bus 1 is provided with a nonfused class
El contractor. The maximum fault duty on this 2.4 kV bus is well within the 50 000 kVA
interrupting rating of the contractor and, therefore, fuses are not required. Motor overload
protection is furnished by the replica-type thermal relay (Device 49) with the instantaneous
overcurrent element (Device 50) applied for phase-fault protection. Separate relaying for
motor locked-rotor protection is normally not justified on motors of this size. Undervoltage
and single-phasing protection is provided for this and the other motors connected to this bus
by Device 27, an undervoltage relay, and by Device 60, a negative-sequence voltage relay
connected to the bus potential transformers. Due to the essential function of the motors
applied on this bus, a high-resistance grounding scheme is utilized. A line-to-ground fault
produces a maximum of two amperes as limited by the 1.72 Q resistor applied in the neutral
transformer secondary. A voltage is developed across the overvoltage relay (Device 59N),
which initiates an alarm signal to alert operating personnel.

The 1250 hp induction motor connected to 2.4 kV bus 2 is provided with a fused class E2
contractor for switching. The R-rated fuse provides protection for high-magnitude faults.
Motor overload protection is furnished by a replica-type thermal relay (Device49). Locked-
rotor and circuit protection for currents greater than heavy overloads is furnished by Device
51. Protection against single-phasing underload is provided by the current-balance relay
(Device 46). instantaneous ground-fault protection is provided by Device 50GS, which is

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Std 141-1993

connected to trip the motor contractor since the ground-fault current is safely limited to 800 A
maximum. Undervoltage and reverse-phase rotation protection is provided by Device 47.

5.5.2.3 Low-voltage protection

Figure 5-19 illustrates several different types of 480 V unit substation operating modes.
Buses 1, 2, and 3, for example, represent a typical low-voltage industrial spot network system
that is often used where the size of the system and its importance to the plant operation
require the ultimate in service continuity and voltage stability. Multiple sources operating in
parallel and properly relayed provide these features. The circuit breakers are provided with
solid-state trip devices as the overcurrent protection means. Ground-fault protection is also
indicated and would be supplied either as an optional modification to the trip device on the
respective circuit breaker, or as a standard zero-sequence relaying scheme on feeder circuits.
For tripping of transformer secondary main circuit breakers and protecting the secondary
winding, a relay located in the transformer neutral provides another convenient approach.

Since the trip devices of the three main circuit breakers supplying 480 V buses 1, 2, and 3
would normally be set identically to provide selectivity with the tie circuit breakers feeding
the 3000 A bus and the other 480 V feeder circuit breakers for downstream faults, directional
relays should be provided on these circuit breakers. This will permit selective operation
between all 480 V feeder circuit breakers and the main circuit breaker during reverse current
flow conditions for transformer or primary faults. Directional relays might also be applied to
each of the service-tie circuit breakers feeding the 3000 A bus duct so as to provide selective
operation between these interrupters for transformer secondary bus faults.

To protect the 800 A frame size feeder circuit breakers from the high level of available fault
current at secondary buses 1, 2, 3, and 5, current-limiting fuses should be applied in combina-
tion with each circuit breaker. Since the tie circuit breaker at bus 5 is normally closed, the
main circuit breakers are also provided with directional relays to ensure selective operation
between mains for upstream faults.

The unit substation feeding 480 V bus 4 is a conventional radial arrangement and, except for
the addition of ground-fault protection, the circuit breakers shown are equipped with standard
trip devices. Bus 6 is fed from a delta-connected transformer and is provided with a ground-
fault detection system with both a visible and an audible signal. The small low-current frame-
size circuit breakers at this bus have standard trip devices only and do not require the assis-
tance of current-limiting fuses as a result of the lower fault duty on the load side of the
1000 kVA transformer.

5.5.3 Relaying for an industrial plant with local generation [B59], [B66], [B76], [B77]

When additional power is required in a plant that has been generating all its power, and a par-
allel-operated tie with a utility system is adopted, the entire fault-protection problem should
be reviewed, together with circuit breaker interrupting capacities and system component
withstand capabilities. In figure 5-20 the following assumptions are made:

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a) All circuit breakers in the industrial plant are capable of interrupting the increased
short-circuit current.

b) Each plant feeder circuit breaker is equipped with inverse-time or very inverse-time
overcurrent relays with instantaneous units.

c) Each of the generators is protected by differential relays and also has external fault
backup protection in the form of generator overcurrent relays with voltage-restraint
or voltage-controlled overcurrent relays, as well as negative-sequence current relays
for protection against excessive internal heating for line-to-line faults.

d) The utility company end of the tie line will be automatically reclosed through syn-
chronizing relays following a trip-out.

e) The utility system neutral is solidly grounded and the neutrals of one or both plant
generators will be grounded through resistors.

f) The plant generators are of insufficient capacity to handle the entire plant load; there-
fore, no power is to be fed back into the utility system under any condition.

UTIL ITY SUBSTATION

Figure 5-20— Industrial plant system with local generation

236

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Std 141-1993

Protection at the utility end of the tie line might consist of three distance relays or time over-
current relays without instantaneous units. If the distance relays were used, they would be set
to operate instantaneously for faults in the tie line up to 10% of the distance from the plant,
and with time delay for faults beyond that point in order to allow one step of instantaneous
relaying in the plant on heavy faults. If time overcurrent relays were used, they would be set
to coordinate with the time delay and instantaneous relays at the plant. At the industrial plant
end of the tie at circuit breaker 1 , there should be a set of directional overcurrent relays for
faults on the tie line, or reverse power relaying to detect and trip for energy flow to other
loads on the utility system should the utility circuit breaker open, or both.

The directional overcurrent relays are designed for optimum performance during fault con-
ditions. The tap and time dial should be set to ensure operation within the short-circuit
capability of the plant generation, and also to be selective to the extent possible with other
fault-clearing devices on the utility system.

The reverse power or power directional relay is designed to provide maximum sensitivity for
flow of energy into the utility system where coordination with the utility protective devices is
not a requisite of proper performance. A sensitive tap setting can be used, although a small
time delay is required to prevent nuisance tripping that may occur from load swings during
synchronizing.

Due to this time delay a reverse power relay trip of circuit breaker 1 alone may be too slow to
prevent generator overload in the event of loss of the utility power source. Further, the
amount of power flowing out to the other utility loads may not at all times be sufficient to
ensure relay pickup. A complete loss of the plant load can only be prevented by early detec-
tion of generator frequency decay to immediately trip not only circuit breaker 1 , but also suf-
ficient nonessential plant load so that the remaining load is within the generation capability.
An underfrequency relay to initiate the automatic load shedding action is considered essential
protection for this system. For larger systems, two or more underfrequency relays may be set
to operate at successively lower frequencies. The nonessential loads could thereby be tripped
off in steps, depending on the load demand on the system.

The proposed relay protection for a tie line between a utility system and an industrial plant
with local generation should be thoroughly discussed with the utility to ensure that the inter-
ests of each are fully protected. Automatic reclosing of the utility circuit breaker with little or
no delay following a trip-out is usually normal on overhead lines serving more than one cus-
tomer. To protect against the possibility of the two systems being out of synchronism at the
time of reclosure, the incoming line circuit breaker 1 can be transfer-tripped when the utility
circuit breaker trips. The synchro-check relaying at the utility end will receive a dead-line
signal and allow the automatic reclosing cycle to be completed. Reconnection of the plant
system with the utility supply can then be accomplished by normal synchronizing
procedures.

Generator external-fault protective relays, usually of the voltage-restraint or voltage-
controlled overcurrent type, and negative-sequence current relays provide primary protection
in case of bus faults and backup protection for feeder or tie line faults. These generator relays

237

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will also operate as backup protection to the differential relays in the event of internal
generator faults, provided there are other sources of power to feed fault current into the
generator.

5.6 Protection requirements

The primary purpose of a coordination study is to determine satisfactory ratings and settings
for the distribution system protective devices. The protective device settings should be chosen
so that pickup currents and operating times are short, but sufficient to override system tran-
sient overloads such as inrush currents experienced when energizing transformers or starting
motors. Further, the devices should be set for selective operation so that the circuit interrupter
closest to the fault opens before other devices.

Determining the ratings and settings for protective devices requires familiarity with the
NEC [BIO] requirements for the protection of cables, motors, and transformers, and with
IEEE Std C57. 12.00- 1987 [B45] for transformer magnetizing inrush current and transformer
thermal and magnetic stress damage limits.

5.6.1 Transformers [B43]

5.6. 1.1 Maximum overcurrent protection

The NEC [BIO], Article 450-3, specifies the maximum overcurrent level at which the trans-
former protective devices may be set. If there is no secondary protection, transformers with
primaries rated for more than 600 V require either a primary circuit breaker that will operate
at no more than 300% or a fuse sized not greater than 250% of transformer full-load current.
Better protection will be realized with breaker settings or fuse ratings lower than these NEC
maximum levels. The actual value depends on the nature of the specific load involved and the
characteristics of the downstream protective devices. When both primary and secondary pro-
tective devices are provided, the maximum protective levels depend on the transformer
impedance and secondary voltage. These maximum levels of protection, taken from NEC,
table 450-3(a)(2)(b), are shown in table 5-1.

Transformers with primaries rated 600 V or less require primary protection rated at 125% of
full-load current when no secondary protection is present, and 250% as the maximum rating
of the primary feeder overcurrent device when secondary protection is set at no more than
125% of transformer rating. Certain exceptions to these requirements for smaller-sized trans-
formers, detailed in NEC, Article 450-3, are intended to permit the application of protective
devices having standard ratings normally available. The permissible circuit breaker setting is
generally higher than the fuse rating setting due to their differences in the circuit opening
characteristics in the overload region.

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Table 5-1— Maximum overcurrent protection (in percent)

Transformer

rated

impedance

Transformers with primary and secondary protection

Primary

Over 600 V

Secondary

Over 600 V

600 V or below

Circuit

breaker

setting

Fuse

rating

Circuit

breaker

setting

Fuse

rating

Circuit breaker
setting or fuse
rating

No more than 6%

600

300

250

More than 6% but
no more than 10%

400

300

250

225

250

5.6. 1.2 Transformers withstand limits

In the years prior to the adoption of IEEE Std C57. 109-1985 [B51], the time limits defining
transformer withstand capability were based on the following values of time and current,
shown in Table 5-2.

Table 5-2— Transformer withstand limits prior to IEEE Std C57.109-1985

Impedance

Current

Time

(percent)

(time base value)

(seconds)

16.6

7 and above

14.3 or less

At levels of current in excess of about 400-600% of full load, the transformer withstand char-

acteristic can be conservatively approximated by a constant I~t (heating) plot, which is repre-
sented by a straight line of minus 2 slope extending to and terminating at the appropriate
short-circuit withstand point.

It has been widely recognized that damage to transformers from through faults is the result of
mechanical and thermal effects. The former, in fact, has gained increased recognition as a
major factor in transformer failures. Accordingly, two standards significantly revise the famil-
iar ANSI withstand point: IEEE Std C57. 109-1985 [B51] for liquid-filled transformers and
IEEE Std C57. 12. 59-1989 [B47] for dry-type transformers. A complete discussion of this
subject is given in Chapter 10 of IEEE Std 242-1986 [B57], and in the Appendix of IEEE Std
C37. 91-1985 [B43] .

239

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CHAPTER 5

The following discussion briefly reviews the through-fault protection guidelines for Category
I, dry-type transformers (5-500 kVA single-phase, and 15-500 kVA three-phase); Category II
of dry and liquid-filled transformers (501-1667 kVA single-phase, and 501-5000 kVA three-
phase); and Category III of liquid-filled transformers (1668-10 000 kVA single-phase, and
5001-30 000 kVA three-phase). The through-fault protection curves take into consideration
the fact that transformer damage due to mechanical effects is cumulative, and the number of
through-faults to which a transformer can be exposed is different, depending on the trans-
former application.

A straight line curve having an I 2 t constant of 1250 from 2-100 s has been established for
Category I transformers for both frequently and infrequently occurring faults. Two through-
fault protection curves have been established for both Category II [figures 5-21(a) and
5-2 1(b)] and Category III (figure 5-22) transformers. One curve is for those applications
where faults occur frequently, typically more than 10 in a transformer lifetime, and the sec-
ond is for infrequently occurring faults, typically not more than 10.

Where secondary-side conductors are enclosed in conduit, busway, or otherwise isolated, as
found in industrial, institutional, and commercial systems, the incidence of faults is extremely
low and the infrequent fault curve may be used to determine the settings of main secondary
devices, primary devices, or both. In contrast, transformers with secondary-side overhead
lines have a relatively high exposure to through-faults, and the use of reclosing-type protec-
tive devices may subject the transformer to repeated current surges from each fault. In these
cases, the frequent fault withstand curve should be used.

Another consideration is a relative shift in the damage point that occurs in delta-wye trans-
formers with the wye connected secondary and its neutral point grounded. A secondary
single-phase-to-ground fault of one per unit value (using the three-phase fault values as a
base) will produce a fault current of one per unit in the delta of the primary winding, but
results in only 0.58 per unit current in the line to the delta winding that contains the protective
device. Therefore, a second damage characteristic, corresponding to that provided by IEEE
Std C57. 109- 1993 [B51] and derated for a wye-wound solidly grounded neutral should be
plotted at 0.58 per unit of the normal characteristic.

5.6. 1.3 Other protection considerations

In selecting the settings or ratings of the primary protective device, the following items
should be known and considered:

a) Voltage rating of the system

b) Rated load and inrush current of the transformer

c) Short-circuit duty of the supply system in kilovoltamperes

d) Type of load, whether steady, fluctuating, nonlinear, or subject to heavy motor, weld-
ing, furnace, or other starting surges

e) Selective coordination with other protective devices

Relays, when used in combination with power circuit breakers for protection of a transformer
primary circuit, should have a time-current characteristic similar to that of the first down-

240

TIME (SECONDS)

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

THROUGH-FAULT PROTECTION CURVE FOR
FAULTS THAT WILL OCCUR FREQUENTLY
(TYPICALLY MORE THAN TEN IN A TRANS-
FORMER’S LIFETIME)

THROUGH-FAULT PROTECTION CURVE FOR
FAULTS THAT WILL OCCUR INFREQUENTLY
(TYPICALLY MORE THAN TEN IN A TRANS-
FORMER’S LIFETIME)*

2000

1000

500

200

100

0.1

■

\\\v

W \ v

% T

121087654
RANSFORMER IMPED/

WCE

100% OF MAXIMUM POSSIBLE:

Pt=k
— WHERE

/= SYMMETRICAL FAULT CURRENT IN
TIMES NORMAL BASE CURRENT
_ (IEEE STD C57. 12.00- 1993)

k = CONSTANT DETERMINED AT

MAXIMUM / WITH t = 2 SECONDS

i 1 1 1 —

_i i i I i_

2 5 10 20 50

TIMES NORMAL BASE CURRENT
(2a)

TIMES NORMAL BASE CURRENT
(2b)

*This curve may also be used for backup
protection where the transformer is exposed
to frequent faults normally cleared by high-
speed relaying.

Source: IEEE Std C57. 109-1993.

NOTES

1 — Sample I 2 t = k curves have been plotted for selected transformer short-circuit impedances as noted
in 2a.

2 — Low current values of 3.5 and less may result from overloads rather than faults. An appropriate
loading guide should be referred to for specific allowable time durations.

Figure 5-21 (a)— Category II liquid-filled transformers

241

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CHAPTER 5

CATEGORY II TRANSFORMERS
501 to 1 667 kVA single-phase
501 to 5000 kVA three-phase

THROUGH
FOR FAUL1
FREQUENT
10 IN TRA

FAULT P
rS THAT
LY, TYPK
MSFORM

ROTECTI
WILL OC
:ally m

ER LIFET

ON CURVE
CUR

ORE THAN
ME

THROUGH
FOR FAULT
INFREQUE
10 IN TRAI

FAULT P
S THAT
MTLY, TY
JSFORM

ROTECTI
WILL OC
1C ALLY
ER LIFET

ON CURVE
CUR

NOT MORE
ME

THAN

l 2 t = 1

250

i i I s

:ii
: !

12 1

0 8 6

% TRAIN
IMPEC

4 OR LES

SFORMER
DANCE, Z

For fault c
1 00% m

urrents f
aximum

om 70% to
possible;

This curve
backup pr
transform

may als
section
5r is expc

o be usee
where th
sed to

for

For fault currents less than 70%
maximum possible:

1 2 t = 1250 for 0.255 Z 2 <t< 1 02 s

Z = transformer impedance, %

frequent f
by high-sp

aults nor
eed rela

mally cle
fS

red

times normal base curren

0.5

10 20 50 1 2

I, TIMES NORMAL BASE CURRENT

Source: IEEE Std C57. 12.59- 1989.

Figure 5-21 (b)— Category II dry-type transformers

stream device. Pickup of the time-delay element may typically be 150-200% of the trans-
former primary full-load current rating. The instantaneous pickup setting should be set at
150-160% of equivalent maximum secondary three-phase symmetrical short-circuit current
to allow for the dc component of fault current during the first half-cycle. The setting should
also permit the magnetizing inrush current to flow. In general, the transformer inrush current
is approximately 8 to 12 times the transformer full-load current for a maximum period of
0.1 s. This point should be plotted on the time-current curve, and it should fall below the
transformer primary protection device curve. If there is more than one transformer connected
to this feeder, the pickup of the time-delay element should not exceed 600% full-load current

242

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IEEE
Std 141-1993

THROUGH-FAULT PROTECTION CURVE FOR
FAULTS THAT WILL OCCUR FREQUENTLY
(TYPICALLY MORE THAN FIVE IN A TRANS-
FORMER’S LIFETIME)

THROUGH-FAULT PROTECTION CURVE FOR
FAULTS THAT WILL OCCUR INFREQUENTLY
(TYPICALLY MORE THAN FIVE IN A TRANS-
FORMER’S LIFETIME)*

2000

1000

500

200

100

0.1

■

% T

121087654
RANSFORMER IMPED/

1NCE

100% OF MAXIMUM POSSIBLE:
h=k
-WHERE

/= SYMMETRICAL FAULT CURRENT IN
TIMES NORMAL BASE CURRENT
(IEEE STD C57.12.00-1 993)
k= CONSTANT DETERMINED AT

MAXIMUM / WITH t-2 SECONDS
1 1 1 L

—

2 5 10 20 50

TIMES NORMAL BASE CURRENT
(3a)

TIMES NORMAL BASE CURRENT
(3b)

*This curve may also be used for backup
protection where the transformer is exposed
to frequent faults normally cleared by high-
speed relaying.

Source: IEEE Std C57. 109-1993.

NOTES

1 — Sample I 2 r = k curves have been plotted for selected transformer short-circuit impedances as noted
in 3 a.

2 — Low current values of 3.5 and less may result from overloads rather than faults. An appropriate
loading guide should be referred to for specific allowable time durations.

Figure 5-22— Category III transformers

243

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CHAPTER 5

of the smallest transformer, assuming that the transformers have secondary protection and an
impedance of 6% or less. When used in the transformer secondary circuit, the pickup of the
time-delay element should also be between 150 and 200% full-load current of the transformer
secondary rating. A typical circuit configuration is illustrated by the one-line diagram insert
in figure 5-27.

5.6.2 Feeder conductors

Restrictions that apply are provided in the NEC [BIO], Protection of feeders or conductors
rated 600 V or less shall be in accordance with their current-carrying capacity as given in
NEC [B10] tables, except where the load includes motors. In this case it is permissible for the
protective device to be set higher than the continuous capability of the conductor (to permit
coordination on faults or starting the largest connected motor while the other loads are
operating at full capacity), since running overload protection is provided by the collective
action of the overload devices in the individual load circuits. Where protective devices rated
800 A or less are applied that do not have adjustable settings that correspond to the allowable
current-carrying capacity of the conductor, the next higher device rating may be used. Other
exceptions are allowed in the NEC, Article 240-3, such as capacitor and welder circuits and
transformer secondary conductors.

Feeders rated more than 600 V are required to have short-circuit protection, which may be
provided by a fuse rated at no more than 300% of the conductor ampacity or by a circuit
breaker set to trip at no more than 600% of the conductor ampacity. Although not required by
the NEC [B10], improved protection of these circuits is possible when running overload pro-
tection is also provided in accordance with the conductor ampacity.

The flow of short-circuit current in an electric system imposes mechanical and thermal
stresses on cable as well as circuit breakers, fuses, and the other electric components. Conse-
quently, to avoid severe permanent damage to cable insulation during the interval of short-cir-
cuit current flow, feeder conductor damage characteristics should be coordinated with the
short-circuit protective device. The feeder conductor damage curve should fall above the
clearing-time curve of its protective device.

This damage curve represents a constant I~t limit for the insulated conductor. It is dependent
upon the maximum temperature that the insulation can be permitted to reach during a tran-
sient short-circuit condition without incurring severe permanent damage. Recommended
short-circuit temperature limits, which vary according to the insulation type, are published by
cable manufacturers. For any particular magnitude of current, the time required to reach the
temperature limit can be determined from one of the following equations.

For copper conductors:

/\ 2

t = 0.0297

log

(r 2 + 234)
10 (r 1 + 234)

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APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

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Std 141-1993

For aluminum conductors:

I \ 2

j\ t = 0.0125

{T 2 + 228)
1 ° gl0 (r l + 228)

where

I = rms current in amperes
t = time in seconds

A = conductor cross-sectional area in circular mils
T j = initial conductor temperature in °C

T 2 = final conductor temperature in °C (short-circuit temperature limit)

If the initial and short-circuit temperatures are known, these equations can be used to con-
struct a conductor damage curve which is valid for time intervals up to approximately 10 s.
Since the initial temperature depends upon the cable loading and ambient conditions, and
therefore cannot usually be determined accurately, it is common to conservatively assume
that the initial temperature is equal to the rated maximum continuous temperature of the
conductor.

5.6.3 Motors

5.6.3. 1 Large alternating-current rotating apparatus

(See IEEE Std C37. 96-1988 [B44].) The protection of an ac induction motor is a function of
its type, size, speed, voltage rating, application, location, and type of service. In addition, a
motor may be classified as being in essential or nonessential service, depending upon the
effect of the motor being shut down on the operation of the process or plant. Although the dis-
cussion earlier in this chapter on the different types of protective devices indirectly touches
on some of the problems associated with protecting motors, it is worthwhile to examine such
an important subject from the standpoint of the machine itself.

Unscheduled motor shutdowns may be caused by the following:

a) Internal faults

b) Sustained overloads and locked rotor

c) Undervoltage

d) Phase unbalance or reversal

e) Voltage surges

f) Reclosure and transfer switch operations

The ideal relay scheme for an induction motor must provide protection against all these haz-
ards. In the following text, the relaying approach to protect against each of these problems
will be discussed in general terms. Later in the chapter, several specific applications will be
discussed in detail. For a complete discussion on motor protection, see Chapter 9 of IEEE Std
242-1986 [B57] .

245

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a) Internal faults. Internal fault protection for induction motors can be obtained by
either overcurrent relays or, preferably, percentage differential relays, as described in

5.3.5. 1. When the supply source is grounded, separate and more sensitive ground-
fault protection can be provided using the relaying schemes described in 5.3.7. 1 and

5. 3. 7. 2. The preferred solution is to use the zero-sequence approach for ground-fault
relaying where all three phase leads are passed through the single window-type cur-
rent transformer. This eliminates false tripping due to unequal current-transformer
saturation and allows the use of a fast, sensitive ground-fault relay setting.

b) Sustained overloads and locked rotor. Conventional overcurrent relays do not provide
suitable protection against sustained overloads because they will overprotect the
motor if set to pickup for the normal overloads encountered. That is, the relay will not
allow full use of the thermal capability of the motor and in many cases will not pro-
vide sufficient time delay to permit complete starting. This is shown in figure 5-23,
where for most conditions less than locked-rotor current there is too much margin
between the motor thermal capability curve and the relay operating time characteris-
tic. With a higher pickup and appropriate time-dial setting as shown, the overcurrent
relay will provide excellent locked-rotor and short-circuit protection of the motor.

Figure 5-23— Motor and protective relay characteristics

246

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

Thermal relays, on the other hand, will give adequate protection for light and medium
overloads, allowing loading of the motor close to its thermal capability. In general,
however, thermal relays will not give adequate protection for heavy overloads, locked
rotor, and short circuits. Therefore, in most cases both types of relays should be used
to provide optimum protection for overloads, locked rotor, and short circuits, and
allow maximum use of the motor capability. In this way the characteristics of the pro-
tection can be closely shaped to the motor thermal damage curve.

There are two common types of thermal relays available for motor protection, as dis-
cussed in 5.3.14 and 5.3.16. One operates in response to resistance temperature
detectors embedded in the machine windings, and the other operates in response to
motor current. The latter type normally has adjustable pickup and trip characteristics
to compensate for the motor service factor, as well as the ambient temperature differ-
ences between motor and relay.

Frequently, medium-voltage motors are protected by a contractor with thermal over-
load relays applied in combination with current-limiting fuses, which are intended to
open the circuit for high-fault currents. In addition to matching the overload protec-
tion to the motor thermal capabilities for such applications, it is equally important to
select the fuses so that they protect the contractor by opening faster on currents in
excess of the contractor interrupting rating. Likewise, the overload relays must pre-
vent fuse blowing by tripping before the fuse clears on currents within the contractor
capabilities.

c) Undervoltage. Low voltages can prevent motors from coming up to normal operating
speed, or they can result in overload conditions. Although thermal overload relays
will detect an overload resulting from undervoltage, large motors and medium-volt-
age motors should have separate undervoltage protection. An induction-type under-
voltage relay is usually provided to prevent starting when the voltage is unacceptably
low, and to prevent operation on momentary voltage dips.

d) Phase Unbalance or Reversal. When starting from rest, a single-phase condition (one
line open) will prevent starting, while reverse-phase rotation can have immediate
disastrous results on the motor or the driven equipment. In all cases where such con-
ditions are likely to exist, a phase-failure and reverse-phase relay should be applied.

If not properly protected, three-phase motors are vulnerable to damage when loss of
voltage occurs on one phase. There are numerous causes of such loss of voltage, and
these can occur anywhere in the distribution system. The chief problem resulting
from single-phasing of three-phase motors is overheating, which can cause reduction
of life expectancy or complete failure.

The modem practice of applying three overload devices on three-phase motors
assures detection of single-phasing in most cases. When operating at normal load,
loss of voltage on one phase causes an abnormal current in the remaining phases,
which can cause overheating within the motor at a greater rate than normal load cur-
rent and this must be sensed by the protective devices. However, under some condi-
tions of light loading, three-phase motors can overheat when single-phased, without
being detected by the overload protective devices. Even when operating near rated
horsepower under single-phase conditions, the motor can be damaged prior to

247

IEEE

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CHAPTER 5

response by conventional protective devices. Negative-sequence voltage or current-
balance relays should be considered for protection of motors above 1000 hp against
these conditions [B28].

e) Voltage surges. Voltage surges are transient overvoltages caused by switching or
lightning strokes. They are characterized by a steep wave front. Surge protection
equipment consists of a protective capacitor and arrester that should be connected as
close to the motor terminals as possible [B32]. Further application criteria for treating
this problem are discussed in Chapter 6 of this book.

f) Reclosure and transfer switch operations [ B26] . Under normal operating conditions,
the self-generated voltage of an ac motor lags the bus voltage by a few electrical
degrees in induction motors and by 25 to 35 electrical degrees in synchronous
motors. The operation of a recloser on the utility power supply or the transfer to an
alternate source will cause the power to be interrupted for a fraction of a second or
longer. When power is removed from a motor, the terminal voltage does not collapse
suddenly, but decays in accordance with the open-circuit machine time constant (time
for self-generated voltage to decay to 37% of rated bus voltage). The load with its
inherent inertia acts as a prime mover that attempts to keep the rotor turning. The fre-
quency or phase relationship of the motor self-generated voltage no longer follows
the bus voltage by a fixed torque angle, but starts to separate farther from it (out-of-
phase in electrical degrees) as the motor decelerates.

If the motor is reconnected to the bus voltage with its self-generated voltage at a high
level and severely out-of-phase, dangerous stresses that are both mechanical and
electrical are placed on the motor and its driven load. In addition to possible damage
to the motor, excessive torque may also damage the motor coupling. Furthermore, the
excessive current drawn by the motor may trip the overcurrent protective device.

A check should be made to determine that re-energization occurs at a point where the
motor and load will not be subjected to excessive forces. Protection against this prob-
lem can be provided by certain types of frequency relays that operate as a function of
the rate of change of frequency to remove the motor from the line. An alternate
method is to prevent re-energization until the residual voltage has decayed to a safe
value.

Automatic transfer switching means can be provided with accessory controls that dis-
connect motors prior to transfer and reconnect them after transfer and when the resid-
ual voltage has been substantially reduced. Another method is to provide in-phase
monitors within the transfer controls that prevent transfer until the motor bus voltage
and the source are nearly synchronized.

g) Multifunction motor protective relays, Device 11. Many of the protective functions
just described can now be provided in a single relay enclosure using solid-state
microprocessor technology. Some of the advantages it offers over the single function
relays are as follows:

1 ) Reduction in panel space requirements

2) Simplification in panel wiring

3) Ease in selection of set points

248

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

IEEE
Std 141-1993

4) Measurement and storage of operating data such as full load current, locked-
rotor current, RTD temperatures and percent current unbalance

5) Diagnostic capabilities

6) Ability to communicate with a remote location

5.6.3.2 Small motors

The specific requirements for the protection of small induction motors are specified in Article
430 of the NEC [BIO]. Each motor branch circuit must be provided with a disconnect means,
branch circuit protection, and a motor running overcurrent protective device. Two examples
are shown in figure 5-24.

FUSE

MAGNETIC
MOTOR STARTER
WITH THREE
THERMAL
OVERLOAD
RELAYS

THERMAL
MAGNETIC OR
MAGNETIC ONLY
MOLDED-CASE
CIRCUIT
BREAKER

MAGNETIC
MOTOR STARTER
WITH THREE
THERMAL OVERLOAD
RELAYS

100 hp
INDUCTION

Figure 5-24— Motor protection acceptable to the NEC

The branch circuit disconnect and protective means are generally combined in one device,
such as a molded-case circuit breaker or a fused disconnect switch. The motor running over-
current protection is provided by overload relays. The motor is energized and de-energized by
a controller. This unit may be operated either manually or electrically (magnetic type). The
overload relays open the motor controller to provide motor running overcurrent protection. It
is not uncommon to have the motor controller included in the same enclosure as the motor
branch circuit disconnect and overcurrent protection device. The complete unit is called a
combination motor starter, providing motor branch circuit disconnect and overcurrent protec-
tion along with motor control and running overcurrent protection. The motor branch circuit
overcurrent device must allow the motor to start (without opening on motor inrush current),
but it must open for short circuits.

A combination disconnect and overcurrent protective device must be capable of safely inter-
rupting the circuit under the maximum available short circuit and, in so doing, protect the
branch circuit. The switch should be quick-make-quick-break, horsepower-rated, and capable
of being closed in on a fault of the magnitude available at its application point without

249

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9 1

damage. The switch must safely withstand the I~t and peak let-through current of the fuses
without realizing an immediate failure or change in operating characteristics, which could
lead to problems during normal operation sometime later. In like manner, a combination
starter utilizing either a thermal-magnetic or a magnetic-only circuit breaker must have a
short-circuit rating equal to or greater than the maximum available fault current.

For running overcurrent protection it is necessary to select the proper thermal unit for the
overload relay. All manufacturers’ tables of thermal units are based on the operation of the
motor and controller in the same ambient temperature of 40 °C or less. To apply these devices
properly, the following must be determined:

a) Motor full-load and locked-rotor current from motor nameplate

b) Motor service factor from nameplate

c) Ambient temperature for motor

d) Ambient temperature for controller

e) Motor starting time with load connected

With this information, and following the manufacturer’s recommendation, an adjusted motor
full-load current can be determined to select the proper overload relay thermal unit from the
manufacturer’s table. Then it must be verified that the trip characteristic will permit starting.

Low-voltage motor contactors are now available with integral three-phase overload
protection using solid-state technology. These overload relays do not require separate thermal
units (heaters), since the trip rating can be set over a wide current range. Selectable character-
istics for NEMA Class 10, 20, and 30 (NEMA ICS 1-1988 [B7 1]) may be available to match
the motor-operating characteristics.

Undervoltage protection is inherent in the use of a magnetic controller and three-wire control,
since the control voltage is taken from the line or primary side of the controller. Most mag-
netic motor controllers will drop out when the operating coil voltage drops to 65% of its rat-
ing. All units do not have the same drop-out characteristics, so the actual drop-out voltage
should be determined by test. For many motors the three overload devices may not provide
complete single-phase protection, in which case it can be furnished as a special equipment
modification.

5.7 Use and interpretation of time-current coordination curves

5.7.1 Need and value

Determining the settings and ratings for the overcurrent devices in a power system is an
important task and, when correctly done, assures the intended performance of the system.
Continuity of plant electric service requires that interrupting equipment operate in a selective
manner. This may require longer opening times (for a given current) of the interrupters
successively closer to the power source during faults. The necessity for maximum safety to
personnel and electric equipment, on the other hand, calls for the fastest possible isolation of
faulted circuits.

250

APPLICATION AND COORDINATION OF PROTECTIVE DEVICES

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Std 141-1993

The coordination curve plot provides a graphical means of displaying the competing objec-
tives of selectivity and protection. This method of analysis is useful when designing the pro-
tection for a new power system, when analyzing protection and coordination conditions in an
existing system, or as a valuable maintenance reference when checking the calibration of pro-
tective devices. The coordination curves provide a permanent record of the time-current
operating relationship of the entire protection system.

Actual plotting of the curves on log-log graph paper using a common current scale is essen-
tial because rarely do all the fault protective devices involved have time-current curves of the
same shape, and it is difficult to visualize the relationship of the many different shapes of
curves. A scale corresponding to the currents expected at the lowest voltage level works best.
For example, fault-current protective devices on both sides of a 2400-480 V transformer
should be plotted on the 480 V current scale. To plot 2400 V device time current curves on the
480 V scale, first determine the desired time and current settings on the basis of current
expected on the 2400 V circuit. Then multiply the 2400 V currents by five, the ratio of 2400-
480, to obtain equivalent current at 480 V and plot on the 480 V scale. The time delay setting
may have to be adjusted to obtain the desired time interval with the load-side protective
device.

Usually the coordination plot is made on log-log graph paper with current as the abscissa
(horizontal axis) and time as the ordinate (vertical axis). A choice of the most suitable current
and time settings is made for each device to provide the best possible protection and safety to
personnel and electric equipment and also to function selectively with other protective
devices to disconnect the faulted equipment with as little disturbance as possible to the rest of
the system.

Software is commercially available for the personal computer (PC) which will plot the time-
current curves on the log-log paper from large libraries of device characteristics. These pro-
grams can all but eliminate the time-consuming task of drawing the curves by hand [ B62],

5.7.2 Device performance

The manufacturers of protective devices publish time-current characteristic curves and other
performance data for all devices used in a protection system. The time-current curves of
direct-acting time-delay trip devices, fuses, and time-delay thermal devices include the neces-
sary allowance for overtravel, manufacturing tolerances, etc. The individual time-current
characteristics of overcurrent devices are transposed onto a common curve for selecting coor-
dinated settings or ratings.

Typical relay curves are shown in figure 5-6. Relay time-current curves normally begin at
multiples of 1.5 times pickup current setting, since their performance cannot be accurately
predicted below that value. However, curves showing the approximate expected time-current
performance of lower values can usually be obtained from the manufacturer, if required. The
relay time-current curves define the operating time of the relay alone and do not include any
circuit breaker interrupting time.

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5.7.2. 1 Time-delay relays

There are three criteria that should be observed when selecting the characteristics and settings
of time-delay relays for selective operation. These criteria are as follows:

a) Allow adequate time margin between relays

b) Use relays having the same characteristics

c) Set relays closer to the source with a higher pickup current

The time-current characteristics of relays are represented by families of single line curves,
see figure 5-6, which represent the time to close the relay contact with a specific current flow-
ing. A time interval must be added to the second relay in a chain because it continues to see
fault current until the circuit breaker associated with the first relay opens and the arc is extin-
guished. This time is nominally 5-8 cycles for the circuit breakers commonly used in indus-
trial systems, although the actual contact parting time will be 3-5 cycles. After the first circuit
breaker has opened the circuit and de-energized the second relay, the contacts of that relay
(induction-disk type) will continue to coast for 0.1 s due to the inertia of the induction disk to
which the movable contact is attached.

Breaker operating time (5 cycles)
Relay overtravel (disk inertia)
Relay tolerance and setting errors
Allowable time interval

Handset

Set using instruments

0.083 s

0.10 s

0.217 s

0.117s

0.40 s

0.30 s

A total time margin of 0.40 s at maximum fault current is sufficient to afford satisfactory
selectivity between inverse-time relays. As shown in the tabulation, this includes a safety fac-
tor of 0.217 s to cover manufacturing variations and inaccuracies in positioning of the time
dial or lever when setting the relay. Where it is desired to keep the device operating times to a
minimum, the time margin can be safely reduced to approximately 0.30 s when the time
delay setting is accurately set using current and timing instruments. Further reduction of this
margin (to approximately 0.20-0.25 s) is possible with solid-state relays which reset rapidly,
since there is no disk inertia to account for.

For best results, relays having the same characteristic shape, i.e., very inverse, should be
selected. When two induction relays in series having the same shape are set with the appro-
priate time interval at the maximum available fault current, they will also be selective on
lower current values. Where the relay characteristics are different, selectivity can be obtained
provided the relay closer to the source has a less inverse characteristic.

The relay closer to the source should always have a pickup current setting that is higher than
the relay nearer the load. If the pickup setting is lower, the curves of the two relays will cross
each other at some low value of fault current, and the line-side relay will trip first for all cur-
rents below that value.

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These criteria are illustrated in figure 5-25, which is a plot of the time-current curves on a
common current base for the four relays in series. In this case, the power supply was suffi-
cient to provide a constant 250 000 kVA short-circuit duty, assuming no fault current contri-
bution from rotating equipment connected to the 2.4 kV system. On this basis, the maximum
2.4 kV system symmetrical fault current is 20 000 A and the maximum 13.8 kV system sym-
metrical fault current is 10 460 A (60 000 A on a 2.4 kV base). It is also assumed that relay D
at the end of the chain was set at a minimum of 0.5 s.

CURRENT AT 2400 V

Very Inverse Characteristic Curve 4

Moderately Inverse Characteristic Curves 1—3, 5—7

NOTE: The curves are plotted on semilog coordinates for illustrative
purposes only. Normally log-log coordinates are used. Also, in actual
practice tap settings above 8A are seldom required.

Figure 5-25— Selecting time-current curves and relay tap
settings for an industrial plant distribution system

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The three sets of 2.4 kV relays, B, C, and D, were coordinated by selecting time/current set-
tings that would make their operating times 0.4 s apart at the maximum current of 20 000 A.
In the next step, the single set of relays on the 13.8 kV system, relay A, was coordinated with
those on the 2.4 kV system using the same value of fault current available on the 2.4 kV side,
only reflecting the current to the high side for relay A (3480 A at 13.8 kV). Coordination was
accomplished by selecting time/current settings that would give 0.4 s delay between relays A
and B for a 20 000 A fault on the 2.4 kV system. This results in operating times at 20 000 A at
the transformer secondary of 0.55 s, 0.9 s, 1.3 s, and 1.7 s for relays D, C, B, and A, respec-
tively. Using relays all having moderately inverse characteristics, shown by the solid lines of
curves 1,3,5, and 6, the goal of a selectively coordinated system can be achieved.

The following describe the results when the specified criteria are not followed. As shown in
figure 5-25, if relay D were set at a higher pickup current than relay C, shown by the dotted
line of curve 2, then the two relay curves will cross, and selectivity is lost for fault currents
lower than the crossover point even though the required 0.4 s time interval at 20 000 A is met.
In this case, the pickup current of relay C would have to be increased to maintain selectivity
with relay D.

The problem created when relay B has a very inverse characteristic— the dotted line curve
4— instead of an inverse time curve as the others have, is illustrated by curves 4, 5, 6, and 7 in
figure 5-25. Curve 4 meets the requirement that it be 0.40 s slower than curve 3 representing
relay C at 20 000 A. Curves 4 and 5 of relay B represent the two relay characteristics, both
having the same pickup current; however, the protection provided by curve 4 will deteriorate
very rapidly as the short-circuit current decreases. Another resulting problem is that the very
inverse time characteristic of relay B (curve 4) causes its curve to cross that of relay A (curve
6) at a high level of fault current, so that the selectivity is compromised for currents less than
the crossover point. For this particular circuit it would not be too serious, since tripping either
circuit breaker would shut down the whole circuit, but it would still nullify the effectiveness
of the relays in giving indication as to where the trouble was. If the very inverse time charac-
teristic of relay B was retained, the pickup and time dial setting of relay A would have to be
increased (curve 7) in order to be selective with relay B. This would result in much greater
damage during a short circuit and illustrates the problem of incorrectly selecting the relay
characteristics.

When choosing between two combinations of current-tap and time dial settings, either of
which will give a desired operating time at maximum fault current, the combination with the
lower current and higher time dial setting is usually preferable because the relay will be more
sensitive and faster on low values of fault current. Suppose that an operating time of 0.5 s is
desired with a relay connected to 600/5 A current transformers in a circuit with an available
symmetrical fault current of 20 000 A. Relays with 10 A tap and 2.1 time dial setting, curve 1,
or 16 A tap and 1.6 time dial setting, curve 2 will both give the desired time. But in case of a
fault involving only 3000 A, the relay with the 10 A setting would operate in 1.25 s compared
with 2 s for the 16 A tap setting. If the current is still further reduced to 2000 A, the first relay
will still operate in 2.1 s, but the second one will be very slow, since operation is uncertain
when the current is only 1.0 times relay pickup.

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A special problem arises when attempting to coordinate overcurrent devices on opposite sides
of a delta-wye-connected transformer. For line-to-line faults occurring on the wye secondary,
the available fault current through the transformer will be reduced to approximately 87%
(J3/2- 100) of the available three-phase fault current. The highest of the unbalanced line
currents on the delta side, however, will be 100% of the value experienced for a balanced
three-phase fault, and the overcurrent device in this phase will operate faster relative to the
protection on the wye side. The effect that this change in relative operating characteristics has
on coordination for line-to-line faults can be examined graphically by shifting the normal plot
of the delta-side protective device by the ratio of 0.87:1.0. This technique will be illustrated
by an example in 5.8.

5.7. 2. 2 Instantaneous relays

When two circuit breakers in series both have instantaneous overcurrent relays, their selectiv-
ity is dependent solely on their current settings. Therefore, the relays must be set so that the
one nearest the source will not trip when maximum available asymmetrical fault current
flows through the other circuit breaker. This requires sufficient impedance in the circuit
between the two circuit breakers (from cables, transformers, etc.) to reduce the fault current
to the relay nearest the source to less than its pickup setting. If this impedance is insufficient,
selective operation is impossible with instantaneous overcurrent relays and the opening of
both circuit breakers on through faults must be tolerated.

Usually the impedance of a transformer is sufficient to achieve selectivity between an instan-
taneous relay on a primary feeder and the instantaneous trip coil of a low-voltage secondary
circuit breaker. Also, the impedance of open transmission lines may be sufficient to provide
the necessary differential in short-circuit current magnitude to permit the use of instantaneous
relays at both ends.

Generally, instantaneous relays at opposite ends of in-plant cable systems are not selective
because the circuit impedance is too low to provide the necessary current differential.

Applications involving both phase overcurrent and residually connected ground relays should
be reviewed carefully to determine that steady-state and transient error currents are below the
instantaneous pickup setting of the relay. The instantaneous element in a residually connected
scheme may not be able to be set at all due to these transient error currents and are normally
not furnished.

Instantaneous attachments are generally furnished on all time-delay overcurrent relays on
switchgear equipment so that they will be interchangeable, but they should be employed for
tripping only when applicable. The fact that a relay setting study reveals that some of the
instantaneous relays must be made inoperative should not be interpreted as a sign of a poorly
designed protective system.

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5. 7.2. 3 Low-voltage circuit breakers

The time-current characteristics for typical low-voltage power circuit breakers with solid-
state trip devices are represented by bands of curves shown in figure 5-26. The maximum and
minimum operating time curves define the operating characteristic of the trip device. The
very narrow bandwidth of the trip characteristic is achieved by the use of high-quality, indus-
trial-grade, solid-state components, and permits several breakers to be closely coordinated
without excessively high current or time-delay settings. Long-time delay, short-time delay,
and instantaneous and ground-fault characteristics are available as required, and all are indi-
vidually adjustable in both current and time delay, either by means of discrete tap settings or
a continuously adjustable setting. To achieve this level of selectivity, power circuit breakers
utilize short-time delay trips. The equipment protected by this breaker must be designed to
handle the available short-circuit current for the duration of the short-time delay.

Figure 5-27 shows the relative operating characteristics of two circuit breakers with solid-
state trip devices applied in series, and illustrates how selectivity is achieved between circuit
breakers having different combinations of long-time, short-time, and instantaneous trip ele-
ments. Since all tolerances and operating times are included in the published characteristics
for low- voltage circuit breakers, to establish that selectivity exists requires only that the plot-
ted curves do not intersect. The 1600 A switchgear must be braced to withstand the maximum
short-circuit current for the duration of the short-time delay setting of 0.1 s (6 cycles) shown
in figure 5-27.

It should be recognized that providing selectivity to the load-side devices may result in
equipment bus structures being underprotected. The standards for such equipment, ANSI/UL
891-1984 [B21] for switchboards, ANSI/UL 845-1987 [B20] for motor control centers, and
ANSI C37. 20. 1-1987 [B37] for low-voltage metal-clad switchgear, specify a typical with-
stand time duration of three cycles, whereas the minimum short-time delay time is 0.1 s
(6 cycles). Where this condition exists, additional bus bracing will be required or an instanta-
neous trip must be used.

5.7. 2. 4 Fuses

Typical power fuse performance curves are shown in figure 5-28. As with low-voltage circuit
breakers, the total operating range is described by a band that is formed by two published
characteristic curves, the minimum melting time, and the total clearing time. The minimum
melting time curve, forming the lower boundary, represents the melting characteristic and is
typically plotted to a tolerance of -0% to +20% of time. The total clearing time curve, form-
ing the upper boundary, represents the maximum operating time. In this manner, the manu-
facturing tolerance and arcing time are all included within the band described by these
curves. The total clearing characteristic of a load-side interrupter may need to be coordinated
with the minimum melting characteristic of a line-side fuse to prevent any deterioration of its
rating or change in its normal opening time.

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RATIO OF ACTUAL CURRENT TO CIRCUIT BREAKER RATING

Figure 5-26— Adjustability limits of low-voltage power circuit
breaker trip devices (ranges may vary with manufacturer)

5.7.2.5 Ground-fault protection

In a balanced three-phase system, ground-fault coordination is achieved using conventional
time-current curves as discussed previously in this subclause. However, care must be exer-
cised when dealing with systems that employ single-phase interrupting devices, such as sin-
gle-pole breakers or fuses. When a single-phase interrupting device operates, the symmetry
of the three-phase system is lost and the use of conventional time-current curves may lead to
erroneous conclusions.

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TRANSFORMER -++■
FULL-LOAD \K

*00 - CURRENT — X

I I I

300 . CIRCUIT BREAKER
MAXIMUM TRIPPING
200 'TIME

50 000 100 000

6x TRANSFORMER
FULL-LOAD CURRENT

r— i

—

UKUUII BntA\tn *

MINIMUM TRIPPING

TIME

1600 A CIRCUIT BREAKER
50 kA INTERRUPTING CAPACITY
' LONG-TIME AND SHORT-TIME TRIP '

. 400 A CIRCUIT BREAKER .
25 kA INTERRUPTING
CAPACITY
LONG-TIME AND
INSTANTANEOUS TRIP

aaamiiiiMMnn

TO OTHER LJ
1000 KVA 4*2

AN D 4 — (51)/

LARGER (t w
SUB- IT

STATIONS T| 38 |, v -

J 480 Y/277 V
A 1000 kVA

575 % Z

B^) 1600 A

400 A C )400A )

PLUG-IN ^
BUSVKAY T

25 000 A
SYMMETRICAL

/MAXIMUM
SYMMETRICAL
-CURRENT AT —
480 V

; MAXIMUM ‘ -

ASYMMETRICAL
'CURRENT AT
480 V

100 1000 10 000 50 000 100 000

CURRENT AT 480 V IN AMPERES X 10

Figure 5-27— Selective tripping time-current characteristic curves
(low-voltage power circuit breakers on secondary unit substations)

When, for example, the main GFP is selectively coordinated with feeder overcurrent devices,
as shown in figure 5-29, a feeder fault to ground will cause one fuse to open without opera-
tion of the GFP. Although this will not clear the fault from the circuit, the system will remain
selectively coordinated when the vector sum of the currents through the other two energized
phases is not large enough to trip the GFP.

The addition of a second level of sensitive GFP devices and devices that open all three poles
of the circuit to each load-side feeder or branch could improve the coordination significantly.

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CURRENT IN AMPERES

Figure 5-28— Typical time-current characteristic curves of fuses

However, the improvement in operation should be considered in view of the cost and avail-
ability of adequately rated equipment.

5.7.3 Preparing for the coordination study [B67], [B80]

The following information will be required for a coordination study:

a) A system one-line diagram showing the complete system details including all protec-
tive device ratings and characteristics, and associated equipment;

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Figure 5-29— One-line diagram and time-current coordination curve
misrepresenting proper fault clearing

b) Schematic diagrams showing protective device tripping functions;

c) A short-circuit analysis providing the maximum and minimum values of short-circuit
current that are expected to flow through each protective device whose performance
is to be studied under varying operating conditions;

d) Normal loads for each circuit and the anticipated maximum and minimum operating
loads and special operating requirements;

e) Machine and equipment impedances and all other pertinent data necessary to estab-
lish protective device settings and to evaluate the performance of associated equip-
ment, such as current and potential transformer ratios and accuracies;

f) All special requirements of the power company intertie, including the time-current
characteristic curve of the utility protection immediately line-side from the system;

g) Manufacturers’ instruction bulletins, time-current characteristic curves, and inter-
rupting ratings of all electric protective devices in the power system;

h) NEC | B 10] or other governing code requirements as a reference.

5.8 Specific examples— applying the fundamentals

To illustrate some of the many factors that should be considered and the problems that arise
when applying the information and principles provided in the previous clauses of this chapter
to an actual industrial power system, the completed coordination curves (figures 5-30 to 5-39)
for the system shown in figure 5-19 will be discussed in detail. Strong emphasis has been
placed on the prime objectives of equipment protection and selective interrupter performance.
Relays that are unresponsive to system overcurrents and have no time-current characteristics
are not shown on the graphical coordination plots. The selection of settings for these devices
is beyond the scope of this text but can be readily determined by referring to the manufac-
turer’s instruction material covering the relays in question.

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The examples given are only intended to be illustrations. Each system encountered in practice
should be analyzed in detail, since effective protective-device selection and coordination
must apply to a specific situation and not a general case.

5.8.1 Setting and coordination of the 13.8 kV system relaying

5.8. 1.1 Primary feeders supplying transformer

The overcurrent relays applied on the 13.8 kV circuits that energize load center distribution
transformers provide the dual function of primary protection for phase and ground faults
occurring on the 13.8 kV cable and transformer primary winding, and backup protection for
faults normally cleared by the secondary devices. Since backup protection requires selective
tripping with the secondary main circuit breaker, the primary protection is usually compro-
mised to the extent necessary to obtain selectivity. This compromise can be minimized by
selecting a relay characteristic that follows the time-current characteristic of the secondary
device as closely as possible.

As shown in figure 5-37, the overcurrent relays (Device 50/5 1 ) chosen for feeders E, G, and J
have an extremely inverse characteristic, and the settings provide a curve that ensures selec-
tive tripping with the secondary circuit breaker over most of the range of secondary fault cur-
rent. A margin of 0.22 s (0.30 minus 0.08) between the upper edge of the secondary main
circuit breaker trip curve and the relay curve at the maximum secondary fault current level is
recommended. An intersection or crossover with the secondary circuit breaker occurs at
midrange of fault current, as shown in figure 5-37, for relay G, and this is regarded as an
acceptable compromise in order that the transformer would be fully protected within its with-
stand limits for all types of faults. The transformer withstand limits are plotted on the curve
for three-phase faults, and also as the equivalent current (0.58 per unit) appearing in the
primary protective device for secondary line-to-ground faults when the secondary neutral is
solidly grounded. The same degree of protection on secondary line-to-ground faults is not
provided for the transformers supplied by feeders E and J, since the primary relays are set
higher to accommodate the other connected loads. If closer protection is desired, a separate
primary device located ahead of the transformer having trip characteristics to provide protec-
tion within the limits specified by ANSI could be provided. Installation of separate protection
ahead of these transformers having a trip characteristic no higher than that shown for relay G
could correct the problem. Clearing could be accomplished either by a separate interrupter
ahead of each transformer (not shown) or by transfer tripping of circuit breakers E and J.

The primary relay pickup or tap value setting is based on three considerations:

a) To enable the feeder and transformer to carry its rated capability plus any expected
emergency overloading;

b) To provide for selectivity with the transformer secondary circuit breaker;

c) To provide protection for the transformer and cable within the limitations set forth in
the NEC [B10], Articles 450-3 and 240-100.

The shift in the trip characteristics of relay G demonstrates the relative performance of the
primary and secondary protective devices for a secondary line-to-line fault. As compared to a

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CURRENT AT 13 8 kV IN AMPERES X 10

0.3 I 2 3 3 »0 20 30 30

15/20/25 MVA v
Z = 8% '

20 1 -sooTs L

|K U L MM 3

100 200 300 300 1000 2000 3000 5000 10 000

1 — I 1 T — 1' 000

.✓RELAY PICKUP CURRENT
^ (OPERATING TIME INDEFINITE)

MOTOR THERMAL
LIMITATION

MOTOR LOCKED-ROTOR
LIMITATION

soo/sf M

*f 2

TIE LINE TO
GENERATOR
BUS

DEVICE SETTINGS

Q^OVERCURRENT RELAY, EXTREMELY INVERSE
0 5 “ TAP AT 5 A

TIME DIAL AT 5

0.3- INSTANTANEOUS AT 35 A

®5I, OVERCURRENT RELAY, MODERATELY INVERSE

0 2 fcftTAP AT 5 A

''"-'Time dial at 3

OVERCURRENT RELAY, MOOERATELY INVERSE

0 1 -i -

(A^TAP AT 5 a

TIME DIAL AT 4 1/2
INSTANTANEOUS AT 38 A

005 @51, OVERCURRENT RELAY, INVERSE

TAP AT 5 A

003 ■ TIME DIAL AT 3/4, 1

15 MVA TRANSFORMER
CATEGORY III

-T MAXIMUM J

| 3-PHASE
. SYMMETRICAL
! CURRENT^ |

t THROUGH^^M -
I RELAYS

-- 1- D AND B FOR -I-
[| FAULT AT Fi
4*- (I TRANSFORMER * ■
\ OUT) ,

— MAXIMUM Oi

3-PHASE

SYMMETRICAL

CURRENT

“^/THROUGH — 005
r RELAYS D AND M

t FOR FAULT AT F2- 0 03
(BOTH

TRANSFORMERS— 002
I IN SERVICE)

3 20 30 50 100 200 300 500

CURRENT AT 13 8 kV IN AMPERES X 10

1000 2000 3000 5000 10 000

Figure 5-30— Phase-relay time-current characteristic curves for
13.8 kV feeders L and M and incoming line circuits

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CURRENT AT 13 8 kV IN AMPERES
10 20 30 50 )00 200 300 500

2000 3000 5000 10000

10 20 30 50 100 200 300

CURRENT AT 13.8 kV IN AMPERES

2000 3000 5000 lOOOO

Figure 5-31 -Ground-relay time-current characteristic curves
for 13.8 kV source and feeder circuits

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CURRENT AT 13.8 kV IN AMPERES X 10
10 20 30 50 100 200 300 500

IOOO 2000 3000 5000 K) 000

10 20 30 50 100 200 300 500

CURRENT AT 13-8 kV IN AMPERES X 10

2000 3000 5000 10 000

Figure 5-32— Phase-relay time-current characteristic curves
for feeder relay at 13.8 kV Bus 3

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CURRENT AT 13.8 kV IN AMPERES X 10

0.5 I 2 3 5 10 20 30 50 100 200 300 500 1000 2000 3000 5000 10 000

CURRENT AT 13.8 kV IN AMPERES X 10

Figure 5-33— Phase-relay time-current characteristic curves
for generator relay at 13.8 kV Bus 3

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three-phase fault, there is a slightly larger range of possible fault currents over which coordi-
nation between the primary relay and secondary circuit breaker is compromised. Had the sec-
ondary overcurrent device been a relay with the same characteristic as the primary relay,
complete selectivity could have been realized, provided a sufficient clearance was maintained
between the curves at a current of approximately 25 000 A (28 700 • 0.87) at 480 V.

The instantaneous overcurrent element (Device 50), employed in conjunction with the time
element (Device 51), is set to be nonresponsive to the maximum asymmetrical rms fault cur-
rent that it will see for a transformer secondary three-phase fault. The symmetrical value of
transformer let-through current is calculated and an asymmetry multiplying factor applied as
determined from the XIR ratio of the impedance to the point of fault. In addition, a 10% safety
margin is added to this calculated setting. When the relayed feeder is energizing more than
one transformer, the magnetizing inrush of the transformer group may be the limiting factor
for the instantaneous trip setting.

In figure 5-35 the overcurrent relays (Device 50/51) for feeders H and I are set to operate
selectively with the totalizing relay at the maximum expected 2.4 kV fault current with about
a 0.4 s delay between curves. The instantaneous element is set to pick up above the 2.4 kV
system asymmetrical fault availability. The pickup setting and characteristics of the
extremely inverse relay afford excellent protection of the transformer by staying below the
damage curve at all current levels.

For feeders serving relatively small transformers, such as the 750 kVA transformer energized
by the bifurcated feeder from circuit breaker J, the short-time thermal withstand capability of
the selected cable size should be checked. The full-load rating of this transformer is 3 1 .4 A at
13.8 kV, and a No. 8 three-conductor cable of approximately 45 A capacity may have been
selected as adequate. A plot of the thermal withstand limit, as shown in figure 5-40, reveals
that the No. 8 cable could be damaged over its length for a 13.8 kV fault exceeding about
3000 A (90 000 A at 480 V). To prevent this possibility, a No. 1 size cable should be selected.

Sensitive and prompt clearing of ground-faults is possible on all 13.8 kV feeders with the
application of the zero-sequence-type current transformer surrounding all three-phase con-
ductors and the associated instantaneous current relay (Device 50GS). Ground-fault sensitiv-
ity on the order of 4-10 A is achieved with this combination, depending on the type of relay
used. No coordination requirement exists with load-side devices, since these feeder circuits
energize transformers with delta-connected primary windings, and ground-faults on the sec-
ondary side do not produce zero-sequence current in the primary-side feeder circuit. The
ground relaying is shown in figure 5-31.

5.8. 1.2 Motor protection

Figure 5-32 shows the degree of overload protection provided for the 2500 hp 2.3 kV motor
energized through the 2500 kVA transformer from 13.8 kV bus 3. The relaying as applied
should protect both the transformer and the motor.

The replica-type thermal relay (Device 49/50) has a tap setting that will trip the circuit
breaker when the motor load current is sustained at 125% of rating for a period of 60 min.

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This pickup setting complies with the NEC [BIO], Article 430-32, since the machine has a
1.15 service factor. The thermal relay operating characteristic is represented as a band in
which the lower limit signifies the operating time when the overload occurs after a period
of 100% load, and the upper limit signifies the operating time when the overload occurs
following zero loading.

The setting for the time element of the phase overcurrent relays (Device 50/51) at breaker P is
determined by the normal starting time and starting-current requirement for the motor and its
locked-rotor thermal limitation. If the permissible locked-rotor time is greater than the
required accelerating time, as in the example shown, the overcurrent relay can be set for
locked-rotor protection. The pickup or tap setting is usually on the order of 50% of locked-
rotor current, and a time lever setting is best determined by several trial starts under actual
conditions. For some motor designs, the allowable locked-rotor time may be less than the
required accelerating time, and for such conditions an overcurrent relay supervised by a zero-
speed switch may be required for locked-rotor protection.

The pickup setting of the instantaneous element of the thermal and phase overcurrent relays
at breaker P is determined by the transformer magnetizing inrush current. Although the mag-
nitude of the inrush current is shown plotted at its approximate minimum possible level of
10 times full load, an actual relay setting of 12 to 14 times transformer full-load rating should
normally be adequate, but can be increased if pickup occurs during trial starts.

The Device 50/51 overcurrent relays also provide primary phase-fault protection for the
feeder cable and transformer, and for this reason two relays are applied. The instantaneous
ground sensor relay, Device 50GS (not shown), set at a minimum tap, completes the protec-
tion for this circuit.

Figure 5-30 illustrates the overcurrent relaying selected for the 9000 hp 13.2 kV synchronous
motor. An extremely inverse characteristic, same as for the 2500 hp motor, is preferred for
Device 50/51, for locked-rotor protection, and for cable and motor fault backup protection.
Although backup overload protection is also provided by the 160% pickup setting of the time
element of Device 50/51, its trip characteristic crosses over the motor thermal damage curve
and does not afford complete protection in the light overload region. The stator winding tem-
perature relay (Device 49), whose operating characteristics are not customarily plotted on the
time-current curves and which is set to trip rather than alarm, will protect the machine in the
region where Device 50/5 1 does not. The time dial setting falls within the limits of allowable
locked-rotor time and required motor-starting time. Since the motor-starting inrush current is
limited by the starting reactor, the setting for the instantaneous element of Device 50/5 1 is
based on the asymmetrical current that may be contributed by the motor to a fault on an adja-
cent circuit. This current is calculated from the subtransient reactance of the machine, and
1.6 and 1.1 multiplying factors are applied to allow for asymmetry and a safety margin.

5.8. 1.3 Generator protection

The 10 MVA generator connected to the 13.8 kV bus 3 has a phase-overcurrent relay with
voltage control (Device 51V) applied as backup protection for three-phase faults occurring on
the 13.8 kV bus, or on feeder circuits connected to the bus, including the generator circuit.

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The voltage control or voltage restraint feature of the device permits moderate overloads of
the machine without tripping but have increased sensitivity on system faults [B22]. The
instantaneous element for this relay is set above the generator contribution including dc offset
to back up the differential relays for faults into the machine from the system. Additional pro-
tection for phase-to-phase and phase-to-ground faults is provided by the negative- sequence
relay (Device 46) and the ground relay (Device 51G).

Figure 5-33 illustrates the coordination requirements for the circuits connected to the 13.8 kV
bus 3. The generator output under external fault conditions is plotted as a dashed line. The
directional overcurrent relay (Device 67), applied at circuit breaker N as backup to the pilot-
wire relaying, has a pickup setting that permits full loading of the generator over the tie line.
A time lever setting is used that provides selectivity with the 13.8 kV feeder relays of buses
1 and 2 to the extent allowable by the generator short-circuit current, which is too low in
comparison to the system contribution to permit coordination in every case.

The plotted inverse characteristic for the voltage-controlled overcurrent relay (Device 51V) at
circuit breaker O is in effect only when the bus voltage is 80% of normal or less. This level of
voltage can be expected for 13.8 kV feeder faults, and the relay operating time has to coordi-
nate with the overcurrent relays on circuit breakers Pj and N. The current pickup or tap set-
ting is approximately 1 15% of generator rated output.

5.8. 1.4 Cable tie circuit protection

The primary protection for the cable tie circuit between buses 2 and 3 is line differential,
using pilot-wire type relays (Device 87L) at each end of the line. This relay is instantaneous
and sensitive to phase and ground faults occurring only within the area zoned by the current
transformers. For this reason, coordination with other relaying is not required.

Backup phase-fault protection is provided by the overcurrent relay (Device 5 1 ) applied at cir-
cuit breaker M, and the directional overcurrent relay (Device 67) applied at circuit breaker N.
The tap setting for relay M would be selected near 100% of circuit cable ampacity, and the
time lever setting is selected to obtain selectivity with the characteristics of the longest delay
overcurrent relay it overlooks, which is relay Pj on feeder P. This relay characteristic is plot-
ted in figure 5-32. The time lever setting provides a coordinating time interval of 0.6 s at the
current setting of the instantaneous element.

The selection of a directional overcurrent relay at location N in place of a nondirectional type
is necessary because of the limited fault-current contribution from the generator as contrasted
to that supplied from the utility source. The directional characteristic permits a setting that is
sensitive to the generator contribution. If relay N were nondirectional, its setting would have
to coordinate with relay Pj.

5.8. 1.5 Main substation protection

The 13.8 kV main buses 1 and 2 are primarily protected by bus differential relaying (Devices
87B1 and 87B2). Backup protection is provided by the overcurrent relays (Device 51) in a
partial differential scheme so that a fault on one bus feeder will be selectively isolated. The

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setting for the Device 51 relay is plotted in figure 5-30 and identified as relay D. Relay D
must be selective with the feeder relay having the longest time delay connected to buses 1 or
2 and the tie line feeder relay M. Its pickup setting is approximately 140% of the maximum
force-cooled rating of one transformer, and its time lever setting provides a 0.4 s delay inter-
val with relay M at the maximum fault-current level.

The main transformers are individually protected by transformer differential relaying (Device
87T) and, as backup protection, overcurrent relays (Device 51/ 50) are applied at the 69 kV
level and connected also in a summation arrangement. This relay is identified as relay B in
figure 5-30, and its tap setting is also at 140% of the maximum rating of each transformer.
The time lever setting provides a suitable delay interval with relay D at the maximum simul-
taneous fault-current value that can be seen by both relays. The instantaneous element sup-
plied with relay B is set above the maximum asymmetrical current that can be seen by relay B
for a 13.8 kV fault, which occurs with one transformer out of service.

The relay settings now established at the 69 kV main substation entrance must be reviewed
with the power company to ensure that their line-side protective devices will be compatible.
In some cases it may be necessary to compromise selectivity to some degree or to establish
settings with shorter coordinating intervals in order to meet the maximum clearing times per-
mitted by the utility. Also, the setting of Device 67 that looks out into the utility system
should be discussed with the utility to assure compatibility with their system operating
procedures.

5.8. 1.6 Ground-fault protection

Each of the three wye-connected neutrals in the 13.8 kV system are connected to ground
through a 19.9 £2 resistor that limits the ground-fault current available from any transformer
to 400 A. Depending on the number of transformers in service, a range of 400 A minimum to
1200 A maximum is therefore available for ground relay detection. The sensitivity of the
relays applied and their associated current transformers provide a detection capability less
than 10% of the 400 A minimum available.

The ground overcurrent relay settings are plotted in figure 5-31. All transformer feeders and
the 13.8 kV motor feeder are protected with instantaneous current relays energized by zero-
sequence-type current transformers of 50/5 ratio. In terms of primary current, their pickup
sensitivity will be on the order of 5-10 A, depending on CT performance.

The tie-line ground relays at circuit breaker locations M and N are necessarily time delayed
and have identical settings, since selective tripping between the two is not important. Their
time dial setting provides coordination with the main transformer neutral differential relay
(Device 87TN), designated as relay Dj, for faults in the zone that include the transformer sec-
ondary and the line side of the main 13.8 kV circuit breakers.

The next level for selective tripping is relay O, the ground relay in the generator neutral. Its
setting coordinates with 0.4 s delay with relays M and N at the maximum 400 A level. Like-
wise, relay CD in each transformer neutral is only required to be selective with relays M and
N. Its setting, therefore, can be the same as that selected for relay O at the generator.

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Relay D 9 , also in the transformer neutral, must be delayed 0.4 s beyond relay CD at the 400 A
ground-fault level. Relay CD trips the bus tie circuit breaker and thus establishes the location
of the fault as being on one side or the other of the bus tie. Whichever transformer is still
energizing the faulted bus section will then be tripped off by relay D 2 . This relay should de-
energize both primary and secondary windings of the transformer.

5.8.2 Setting and coordination of the 2.4 kV system relaying

5.8. 2.1 Phase protection

Figure 5-35 is the plot of the phase protection for 2.4 kV bus 3 that serves motor loads includ-
ing the 1250 hp induction motor, representing the largest connected machine. The motor ther-
mal damage curve, which must serve as the starting point for properly designing the
protection for any machine, has been plotted as shown. The motor thermal overload relay
(Device 49) satisfactorily matches the machine damage characteristics on overloads up to
approximately 200% of full-load rating and has been set to protect the motor against sus-
tained overloads. Beyond this point, the extremely inverse time relay (Device 51) matches the
motor-damage curve better than Devices 49 and 50 and provides excellent protection in the
locked rotor current region. The 2.4 kV motor circuit fuse is present to protect the contactor
by interrupting heavy fault currents and is sized to withstand locked-rotor current at 10%
overvoltage.

The main and tie circuit breaker partial differential overcurrent relays have been set to be
selective with the motor protection and permit normal expected bus loading. A sufficient
delay in relay operating time has been provided to allow the contactor (or overload relay) to
selectively clear moderate faults should the fault occur on a phase or phases that would
escape detection by the single overcurrent relay (Device 51), or even on the same phase
should the relay fail to operate.

The current-balance relay (Device 46), providing for single-phase protection of the motor,
has no time-current operating characteristic which would affect the relay coordination on
either balanced or unbalanced overcurrent conditions. It has sufficient built-in delay to permit
other relays such as ground relays to operate first when required. A plot of its performance,
therefore, is not relevant and does not appear in the time-current curve. For best protection.
Device 46 should be set at maximum sensitivity provided nuisance tripping does not result.

The time-delay element of the directional overcurrent relay (Device 67) is set for maximum
speed and sensitivity to provide the best protection. The relay should have sufficient delay of
0.1 s minimum for reverse flow of motor contribution current into a primary fault. If an
instantaneous element was used for improved protection, it must be set to pick up above the
current from the motor.

Figure 5-34 illustrates the protection considerations at 2.4 kV bus 1. Here the setting of the
relay at circuit breaker H is dictated by the coordination requirements of the 3750 kVA trans-
former and leaves the 1500 kVA transformer inadequately protected. This is evident by the
fact that the relay curve falls above the transformer damage curve. A 100E primary fuse has
been applied to fill this protection void and appears to do so since its clearing time curve falls

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CURRENT AT 2.4 kV, IN AMPERES X 1 00

10 20 30 50 100 200 300 500 1 000 2 000 3000 5 000 10000

CURRENT AT 2.4 kV, IN AMPERES X 1 00

Figure 5-34— Phase-relay
for 2.4 kV

time-current characteristic curves
Bus 1 coordination

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CURRENT AT 2.4 kV, IN AMPERES X 1 00

10 20 30 40 100 200 300 500 1 000 2 000 3000 5 000 10000

10 20 30 50 100 200 300 500 1 000 2 000 3000 5 000 10000

CURRENT AT 2.4 kV, IN AMPERES X 1 00

Figure 5-35— Phase-relay
for 2.4 kV

time-current characteristic curves
Bus 2 coordination

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CURRENT AT 2.4 kV IN AMPERES

0.9 I 2 3 9 10 20 30 90 100 200 300 900 1000 2000 3000 9000 10000

Figure 5-36— Ground-relay time-current characteristic curves
for 2.4 kV Buses 2 and 3

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to the left of the transformer short-circuit withstand curve. Also, it provides sufficient operat-
ing delay to withstand expected transformer loading continuously as well as transformer
magnetizing inrush for the required 0. 1 s. However, the fuse does not completely protect the
transformer on low-magnitude (arcing) faults due to the crossover of the fuse-interrupting
curve and the transformer-damage curve. If such a failure should occur between the trans-
former and the secondary main circuit breaker R, some amount of transformer damage may
be expected. Improved protection would be provided by using overcurrent relays at the trans-
former primary terminals connected to transfer trip the circuit breaker H.

The protection illustrated in figure 5-34 for 2.4 kV bus 1 serving the 500 hp motor provides a
different approach to locked-rotor protection than that described for the 1250 hp motor.
Again, a thermal overload relay installed in each phase has been set to permit continuous
operation of the motor at rated current and to provide protection for sustained small over-
loads. There is, however, no Device 51 to provide protection for heavy overloads or locked
rotor. The thermal damage curve intersects the maximum operating time of the overload relay
at approximately 300% of full-load current; beyond this point the protection is marginal and
the motor may sustain some damage. This zone of marginal protection is normally considered
economically justifiable on small or noncritical machines. The instantaneous element of the
relay is set to pick up above the motor locked-rotor current (including dc component) to avoid
nuisance tripping on starting. Because of the small size of the transformer, the contactor is
capable of interrupting the available fault current so that current-limiting fuses are not
required in combination with it.

With the installation of the primary fuse, protection against motor damage from single-phase
operation, such as would occur following interruption by one transformer primary fuse, is
provided by the negative-sequence voltage relay (Device 60). The motor-overload relays can-
not be expected to provide protection under these unbalanced operating conditions. The main
circuit breaker overcurrent relay (Device 51) has been set to provide transformer overload
protection and also to be selective with the load-side motor protection and the line-side trans-
former primary fuse.

5.8. 2.2 Ground-fault protection

(See also IEEE Std 242-1986 [B57]). Figure 5-36 illustrates the coordination of the ground-
fault protection on 2.4 kV buses 2 and 3. All the feeder circuit breaker ground relays (Device
50GS) operate from zero-sequence-type current transformers and are set to trip instanta-
neously with maximum sensitivity.

The time-delay product type (Device 87TN) detects ground faults only between the trans-
former and the main circuit breaker and functions to trip the appropriate primary feeder cir-
cuit breaker and secondary main circuit breaker. Since it is not necessary to coordinate this
relay with the feeder ground relays, it is set on the minimum time lever for fastest possible
operation.

The relay 51N-1 must coordinate with relays 50GS and 87TN to trip the 2.4 kV tie circuit
breaker ST for bus faults to ground or as backup to the 2.4 kV feeder circuit breaker ground
relays. Relay 51N-2 must be selective with Device 51N-1. This is the final relay to operate on

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bus faults and must wait for the tie circuit breaker to open and then trip the appropriate main
circuit breaker to isolate the fault.

The ground-fault protection for 2.4 kV bus 1 is not plotted since it is a high-resistance
grounded system that does not trip on a line-to-ground fault. The voltage relay (Device 59N)
senses the presence of a ground fault on the system, which is evidenced by a current flow and
voltage drop through the resistor R, and operates an alarm.

5.8.3 Setting and coordination of the 480 V system protective equipment

5.8.3. 1 Phase overcurrent protection

a) 480 V radial system. 480 V buses 4 and 6 are both radially fed distribution systems
feeding motors or other loads, such as lighting or heating. Figure 5-39, showing
bus 4, illustrates the protection and selectivity considerations which should be eval-
uated.

1) The motor control center (MCC) feeder circuit breaker series trip devices must
provide overload and short-circuit protection for its feeder cables and the MCC
bus structure, and should also be selective with the branch-circuit fuses or
molded-case circuit breakers for all values of fault current up to the maximum
available at the MCC bus. This is accomplished by using long-time and short-
time series trip devices on the feeder circuit breaker. The minimum time-delay
band setting on the short-time characteristic is selective with the total-clearing
characteristic of the molded-case circuit breaker. However, if the branch circuit
device were a 100 A fuse, for example, some selectivity is lost since the fuse
curve overlaps with the knee of the short-time device curve. A constant I t func-
tion on the short-time trip may be available which effectively cuts off the knee
of the curve and when used will provide selectivity with the fuse. As previously
discussed in 5. 7. 2. 3, it is necessary that the MCC bus structure withstand the
available fault current for the duration of the short-time delay setting, shown in
figure 5-39, as 0.18 s (11 cycles). Overload protection is provided by the long-
time element of the breaker and by the fuse when selected to pickup at the lesser
of the feeder cable ampacity or 125% of the MCC load.

It would be difficult, if not impossible, to obtain selectivity between the molded-
case circuit breaker (or a fuse) and the instantaneous tripping characteristic of a
solid-state trip device. The solid-state trip devices are sensitive to rms current
and are activated by a voltage signal that is proportional to the instantaneous
current magnitude. In contrast, a molded-case circuit breaker (or a fuse) requires
a finite amount of let-through energy (.Cr) (although not the same amount) to
open the circuit interrupter and clear the fault.

2) The main secondary circuit breaker series trip devices must provide overload
protection for the load center distribution transformer and short-circuit protec-
tion for the 480 V bus and feeder circuit breakers and must also be selective
with the feeder circuit breaker series trip devices. This can be accomplished by
using long-time and short-time trip devices in the main secondary circuit
breaker with the long-time element set to pick up at the maximum permissible

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CURRENT AT 480 V IN AMPERES X 1000

Kj4- 480 V SUPPLY CIRCUIT BREAKERS
1 65 kA INTERRUPTING CAPACITY

SOLID-STATE TRIP DEVICES
LONG-TIME DELAY PICKUP SET AT 2500 A
SHORT-TIME DELAY SET AT 5X LONG-
TIME DELAY PICKUP AND MAX DELAY
SERVICE BUS TIE CIRCUIT BREAKERS
65 kA INTERRUPTING CAPACITY
SOLID-STATE TRIP DEVICES
LONG-TIME DELAY SET AT 1600 A
SHORT-TIME DELAY SET AT 5X
k LONG-TIME DELAY PICKUP AND
^INTERMEDIATE DELAY

13.8 kV CIRCUIT BREAKER

RELAY, EXTREMELY INVERSE
TAP AT 12 A
TIME DIAL AT 3
l INSTANTANEOUS AT 75 A

TRANSFORMER
WITHSTAND LIMITS
SECONDARY
LINE-TO-GROUND
FAULT

SECONDARY
3 PHASE FAULT

200 300 500 1000 2000 3000 5000 10 000

G NORMALLY
CLOSED

(TYPICAL)

. I

W2000/5*

Ilf 67 ) — V [MIN 1.81 kA SYMM (CD CLOSED)

I 27 kA lMAx 20 3 KA SYMM (CD OPEN)
tsYMM | 480 V

480 V BUS I I BUS 2

TO 480 V
BUS 4 .

FAULT TRIPPING SEQUENCE
Fi SERVICE BUS FEEDER FUSE
F 2 SERVICE BUS TIE CIRCUIT BREAKERS
F 3 BUS I 480 V SUPPLY CIRCUIT BREAKER
AND SERVICE BUS TIE CIRCUIT BREAKER
F 4 BUS I FEEDER CIRCUIT BREAKER
F 5 MCC i MOTOR STARTER
SECONDARY F 6. F 7 BUS I 480 V SUPPLY CIRCUIT
LINE- TO- _ ^BREAKER BY DEVICE 67

I?, 13.8 kV CIRCUIT BREAKER
01 RELAYS, EXTREMELY INVERSE
TAP AT 6 A
TIME DIAL AT 3
INSTANTANEOUS AT 40 A
MAXIMUM FAULT CURRENT SEEN BY SUPPLY
CIRCUIT BREAKERS FOR LOAD-SIDE FAULTS
MAXIMUM FAULT CURRENT SEEN BY
SERVICE BUS TIE CIRCUIT BREAKERS
FOR MCC FAULTS

FOR SERVICE BUS FAULTS

DIRECTIONAL PHASE OVERCURRENT RELAYS (67)
TAP AT 0.5 A
TIME DIAL AT 2
INSTANTANEOUS AT 10 A

MAXIMUM FAULT LEVEL
480 V SYSTEM, SYMMETRICAL
J i I L

200 300 500 1000 2000 3000 5000 10 000

300

200

0 03
0 02

CURRENT AT 480 V IN AMPERES X 1000

Figure 5-37— Phase-protection time-current characteristic curves for
13.8 kV feeder E, G, and J and 480 V Bus 1, 2, and 3 network coordination

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0 03
0 02

CURRENT IN AMPERES X 100

2000 3000 3000 10 000

400 V SUPPLY CIRCUIT BREAKERS
65 kA INTERRUPTING CAPACITY
SOLID-STATE GROUND TRIP DEVICES |
PICKUP SET AT 1200 A
SHORT-TIME DELAY SET AT 0 30 5

\r .'.TTZZ

^FEEDER CIRCUIT BREAKERS
WITH 1000/5 ZERO- SEQUENCE
(DOUGHNUT) CURRENT TRANSFORMER
GROUND RELAY
TAP AT 0 5 A (100 A GROUND CURRENT)
TIME DIAL AT 1/2 /

SERVICE BUS TIE CIRCUIT BREAKERS
65 kA INTERRUPTING CAPACITY
SOLID-STATE GROUND TRIP DEVICES |
PICKUP SET AT 750 A
SHORT-TIME DELAY SET AT 0 10 3

FEEDER CIRCUIT BREAKER
000 A FUSE

-150 h p MOTOR STARTER
200 A FUSE

0 3
0 2

003

002

20 .30 50 100 200 300

CURRENT IN AMPERES X 100

2000 3000 5000 10 000

Figure 5-38— Ground-relay time-current characteristic curves
for 480 V Bus 1 , 2, and 3 network

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RATIO OF ACTUAL CURRENT TO CIRCUIT BREAKER RATING

200 300 500

1000 2000 3000 5 000 10000

1 000

200 300 500 1 000 2 000 3 000 5 000 10000

CURRENT AT 480 V, IN AMPERES X 100

Figure 5-39— Phase protection time-current characteristic curves
for 13.8 kV feeder J 2 and 480 V Bus 4 coordination

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short-time overload capacity of the transformer, and the short-time element set
higher than the maximum motor inrush current. Here again, the switchgear
(switchboard) bus structure must safely withstand the available short-circuit
current for the duration of the short-time delay setting shown in figure 5-39 as
0.32 s (approximately 19 cycles. If the I~t ramp function is provided on the
feeder breaker, it may be necessary to also provide it on the secondary main
breaker as well.

b) 480 V network system. 480 V buses 1 , 2, and 3 comprise a typical spot-network sys-
tem. Figure 5-37, showing these buses, illustrates the protection and selectivity con-
siderations which should be evaluated.

1) Power must not flow out of the network into the supply system as a result of
faults in the supply circuits. Directional overcurrent relays (Device 67), operat-
ing from current transformers in the secondary connections from each supply
transformer, meet this requirement. These relays must be set to trip the associ-
ated 480 V main secondary circuit breaker when current flows into the supply
system in a time before the other two main secondary circuit breakers open as a
result of the operation of their nondirectional protective devices. If the direc-
tional relays are equipped with instantaneous elements having directional con-
trol (some do not have this capability), the instantaneous elements would be set
to pick up above the momentary 480 V induction motor contribution to primary
faults so as to avoid an unnecessary opening of the main circuit breakers for
trouble on a remote circuit.

2) Faults on buses 1, 2, or 3 or on feeders fed from these buses must be cleared
either by the feeder circuit breakers or by the associated 480 V main secondary
and service bus tie circuit breakers in a time before the other service bus tie cir-
cuit breakers open. This can be accomplished by setting the bus tie circuit
breaker and the main secondary circuit breaker trip devices to be selective with
the feeder protective devices, as shown in figure 5-37. Selectivity between a ser-
vice bus tie and the feeder circuit breakers is not achieved when electromechan-
ical trip devices are used. However, when solid-state trip devices are used, the
system is selective for all current values.

Figure 5-37 shows that selectivity between buses 1, 2, and 3 service ties does not
exist since their settings are identical. Where continuity of service is essential
instantaneous bus differential relays should be considered as the alternate means
for providing selectivity between the three buses.

3) Faults on the 3000 A service bus or on feeders fed from this busway must be
cleared either by the feeder circuit breakers or by the service-tie circuit breakers
before the tie circuit breakers open and cause a complete outage. This is accom-
plished by the selective trip-device settings (long-time, short-time delay) on the
tie and supply circuit breakers. A fault that causes the service bus tie circuit
breakers to trip leaves buses 1 , 2, and 3 energized and operating, but causes the
loads on the 3000 A busway to be lost.

From the curves, it is not obvious whether the 800 A fuses integral with the
feeder circuit breakers on buses 1. 2, or 3 are selective with the dual-element

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200 A motor-starter fuses at the motor control centers. This may be determined
by examining the fit let-through characteristics of the two fuses. To coordinate

satisfactorily, the total clearing /T of the 200 A fuse must be less than the melt-
ing fit of the 800 A fuse. Selective coordination can be achieved by referring to
the manufacturers’ selective coordination rating tables.

4) Certain modes of operation could result in the 13.8 kV tie circuit breaker CD
being open. In such cases a fault on any primary circuit would cause high cur-
rents to circulate through this substation as power is transferred between the sep-
arated primary systems. The instantaneous setting of the directional overcurrent
relay would operate to trip the associated 480 V main breaker since it is not
selective with the instantaneous relay of a faulted 13.8 kV breaker that does not
serve this substation. If the settings of the time delay and instantaneous elements
of the directional relays were changed so as to provide selectivity for primary
faults on any 13.8 kV feeder not serving this substation, then selectivity between
the solid-state trips of the 480 V main secondary breakers and the directional
relay would be lost.

To ensure selective operation of all the protective devices during the normal
mode of operation with the 13.8 kV bus tie circuit breaker CD closed, loss of
selectivity must be accepted for certain types of faults should circuit breaker CD
ever be opened. With a fault on a remote primary feeder such as the circuit fed
by 13.8 kV circuit breaker F, the directional relays on the 480 V main supply cir-
cuit breakers of buses 1 and 2 will trip before the relaying on primary feeder F
would selectively isolate the fault. A similar situation arises for any remote pri-
mary feeder fault with the 13.8 kV tie circuit breaker open. Since this is not the
normal mode of operation, it is not considered to be a serious compromise.

c) 480 V double-ended secondary unit substation with normally closed secondary tie.
480 V bus 5 fed from 13.8 kV breakers E and J is a variation of the 480 V spot net-
work previously discussed. The basic protection considerations in item (2) also apply
for this example. The following factors should be considered for optimum protection
and coordination:

1) Directional relays should be applied to the main secondary circuit breakers as
described in the discussion for 480 V buses 1, 2, and 3 to selectively isolate pri-
mary system faults.

2) Faults on either bus section or on feeders fed from the bus must be cleared by
the feeder circuit breakers or by the bus tie circuit breaker and the associated
480 V main secondary circuit breaker before the other 480 V main secondary
circuit breaker operates and causes a complete 480 V outage. This is accom-
plished by setting the long-time and short-time trip devices of the main second-
ary circuit breakers to be selective with the bus tie circuit breaker.

Figure 5-37, although specifically representing buses 1, 2, and 3, illustrates the delay
sequence that would be used for selectively coordinating the device settings for bus 5 as well.

As in the case of 480 V buses 1, 2, and 3, the I~t characteristics of the motor starter and feeder
circuit breaker fuses should be evaluated to ensure coordination between fuses.

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5.8.3.2 Ground-fault protection

The 480 V spot network and buses 4 and 5 in figure 5-19 are shown as being solidly
grounded. At these buses the maximum line-to-ground fault current is virtually equal to the
three-phase value; however, the fault impedance and ground-return path impedance increase
significantly with the distance from the source, and a much lower-magnitude current will
flow. Sensitive relaying should, therefore, be used to ensure that ground-fault currents too low
to be detected by the phase overcurrent trip devices are detected and safely cleared.

Common methods employed to provide this protection are as follows:

a) Solid-state ground trip devices integral with feeder, tie, and main circuit breakers;

b) Zero-sequence current transformers which enclose all phase conductors in feeder cir-
cuits as described in 5. 3. 7. 2;

c) Relays operating from residually connected current transformers in feeder circuits,
tie circuit breakers, and main circuit breakers;

d) Overcurrent relays connected to the secondary of a current transformer sensing the
current in the distribution transformer neutral (not illustrated in this diagram).

Very special care is required when applying ground relays to four-wire secondary selective
systems where the neutral circuit is not switched if selectivity is to be achieved between main
and bus tie circuit breakers (see IEEE Std 142-1991 [B56]). The principles involved in select-
ing coordinated ground-relay settings are the same as those described for phase-protective
devices. Figure 5-38 shows selective ground relaying for buses 1, 2, and 3 spot-network sys-
tems using a definite time ground relay operating from a window-type current transformer
around the feeder cables to motor control centers, and solid-state ground trip devices in the
service bus tie and main circuit breakers.

In a solidly grounded system, the zero- sequence current transformer must be of such a ratio
that it will provide an output current low enough to be within relay ratings and sufficiently
undistorted to accomplish accurate relaying during maximum ground-fault conditions. This is
of special concern when induction disk relays are used. For the system illustrated, a ratio of
1000/5 has been selected. However, ratios as low as 100/5 have been successfully used.

5.9 Acceptance testing (commissioning), maintenance,
and field testing

In order to secure the full benefit that a well-designed protective installation is capable of pro-
viding, the installation should be properly installed and tested. The tests are exacting and
often complex, and should be performed very carefully to avoid endangering persons and
equipment. Where possible, these services should be procured from specialists.

Prior to either testing or maintaining any component or installation, a copy of the manufac-
turer’s instruction book should be obtained and thoroughly reviewed. These books often con-
tain specific acceptance, maintenance, and testing procedures.

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5.9.1 Acceptance testing (commissioning)

The following items, as a minimum, should be included in an acceptance testing
specification:

a) General scope. Items should include a general statement concerning type of testing
organization required, what they shall provide, and the intent of the tests.

b) Applicable codes, standards, and references. A listing of codes, standards, and refer-
ences applicable to the project should be included.

c) Required qualifications of testing organization.

d) Division of responsibility. This section should contain statements of the responsibility
of the owner, engineer, contractor, and testing organization.

e) General requirements. General topics, such as test equipment traceability, test
reports, safety precautions, and temporary power and light, should be covered.

f) Specific work scope. This section should contain an itemized description of equip-
ment to be inspected and tested.

g) Inspection and test procedures. A detailed description by system component specifi-
cations (e.g., switchgear and switchboard assemblies, transformers, relays, cables,
etc.) of the specific inspection and test procedures to be followed should be provided.
This represents the major effort of an acceptance testing program and consists of
visual and mechanical inspections, as well as electrical tests. Many specific electrical
tests are applicable to all components of an electrical power distribution system,
while others may apply more directly to a specific piece of equipment.

h) System function tests. This section should specify the system function tests that
should be performed to assure total system operation upon completion of equipment
tests. It is the intent of system functional tests to prove the proper interaction of all
sensing, processing, and action devices to effect the design end result.

The former include insulation resistance tests, insulation power factor tests, and overpotential
tests. Some tests in the latter category are relay and breaker calibration tests, high-current
tests, contact-resistance tests, dielectric fluid tests, and circuit breaker contact time-travel
tests. Also, these general types of tests may be applied differently, depending upon the spe-
cific component under test and the voltage class of the equipment. NETA ATS-1990 [B75],
provides a list of testing procedures.

5.9.1. 1 General survey and diagramming

In preparation for the acceptance testing, it is necessary for the owner’s engineer or the accep-
tance testing organization to do the following:

a) Study the intended function of each device and the manner in which all the devices
are designed to operate.

b) Check the wiring diagrams to ensure that each device is connected so that it will per-
form its intended function. If no diagrams have been provided, make them or obtain
them, for it will be difficult to do a safe and intelligent job of testing without them.
Preserve the diagrams for future reference and update them when changes or addi-
tions are made.

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c) Compare the diagrams with the actual connections and, when differences are found,
determine whether the error is in the diagrams or in the wiring and correct it.

5.9.1 .2 Visual check of equipment

a) Inspect equipment for damage or misadjustment caused by shipment or installation.

b) Verify that all protective relays, auxiliary relays, trip coils, trip circuit seal-in and tar-
get coils, fuses, and instrument transformers are the proper types and range, as speci-
fied in the project documents.

c) Remove wedges, ties, and blocks installed by the manufacturer to prevent damage
during shipment.

5.9.1. 3 Equipment electrical tests

The following outlines an electrical acceptance testing program. Expertise is required on the
part of the testing organization to properly and safely perform these tests, to interpret and
analyze test results, and to submit a complete test report. (An inspection checklist for record-
ing test values for a typical unit substation is shown in figure 5-40.) This report should reveal
the condition of the system equipment upon arrival at the site and provide data for compari-
son with test results made over the life of the equipment. Recommended procedures for test-
ing and maintenance are provided in many standards publications of ICEA, NEMA, and
IEEE.

a) Switchgear and switchboard assemblies. Insulation resistance tests at specified suit-
able test voltage.

b) Transformers: Liquid-filled

1) Insulation resistance tests

2) Dielectric absorption tests

3) Turns ratio tests at all tap positions (recommended for commissioning only)

4) Sample and test insulation fluid (dielectric breakdown strength, interfacial ten-
sion, power factor, moisture content, and neutralization number) (see IEEE Std
C57. 106-1991 [B50], IEEE Std C57.1 11-1989 [B52] and IEEE Std C57.121-
1988 [B53])

5) Insulation power factor test or ac overpotential test

6) Insulating liquid tests

i) 500-5000 kVA— Spectrographic analysis for dissolved gases

ii) 5001 kVA and larger— Top combustible gas analysis where applicable

c) Transformers: Dry-type (see IEEE C57. 94-1982 [B49])

1) Insulation resistance tests

2) Dielectric absorption tests

3) Turns ratio test at all tap positions

4) Insulation power factor test or ac overpotential test

5) Winding resistance

d) Cables: Medium-voltage

1) Direct-current high-potential step-voltage tests

2) Shield continuity test

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CHAPTER 5

SUBSTATION # ...

Yes

A. High-Voltage Section

Concerning the two-position, three-pole gang-operated air inter-
rupter switches for each feeder,

a. Do the switches operate freely and with the proper action if

“ quick-make quick-break ”?

□

b. Do the three blades make contact at the same time?

□

c. Are the arcing contacts intact?

□

d. Are there insulating barriers between the poles?

□

Has the circuit phase rotation been checked for the two feeders?

□

What are the nameplate data for the three current-limiting fuses
on the transformer primary?

Does the key interlocking system work correctly?

□

Are the stress cones and terminations made correctly?

□

Are the phase buses insulated completely?

□

Are bus connections tight?

□

Have the insulators been checked for cracks, cleanliness, and track-
ing?

□

Have the system ground connections been made to the ground bus?

□

10.

Have the steel plates been provided to prevent access to the high-
voltage compartment?

□

11.

Has a mimic bus been painted on the switchgear?

□

12.

Has any discoloration of current-carrying metal parts occurred?

□

B. Transformer Section

What are the transformer nameplate data?

What are the insulation resistances of the primary and secondary

windings?

a. Primary to ground megohms

b. Secondary to ground megohms

c. Primary to secondary megohms

What are the resistances of the delta-connected primary windings?

a. Phase A to phase B ohms

b. Phase A to phase C ohms

c. Phase B to phase C ohms

□

Has the transformer been checked for leaking conditions?

Have the provisions been made for four 2 %% taps in the high-
voltage windings (two above and two below rated primary voltage)?

□

Tap changer is set at position

Have the connections at the transformer bushings for both the high
side and low side been checked for tightness and good contact sur-

□

faces?

Are the connections to the transformer primary and secondary bush-
ings made through flexible connectors?

□

Have the transformer bushings been checked for cracks?

□

Has the neutral of the transformer secondary been brought out
through a bushing and has it been connected to the neutral bus?

□

Figure 5-40— Typical unit substation inspection checklist

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B. Transformer Section (Cont’d)

Yes

10.

Has the neutral bus been connected to the grounding pad at the
secondary end of the transformer by means of a removable bus-
bar link?

□

11.

Have the transformer accessory devices been checked?

□

12.

Has the phase designation been maintained in connections from the
transformer secondary bushing to the low-voltage bus? (Front to
back, top to bottom, and left to right shall be phase A, phase B, and
phase C, respectively)

□

13.

Has the gas absorber been installed completely?

□

14.

Have provisions been made to install auxiliary fan cooling with all
necessary control devices wired?

□

C. Low-Voltage Section

1. Have buses been provided for between the transformer secondary
bushings and the transformer secondary main circuit breaker?

□

Are the three-phase main bus bars continuous and rated for
amperes?

□

Is the neutral bus continuous and rated for am-

peres?

□

Is the ground bus
a. Continuous?

□

b. Connected to the system ground?

□

c.. Solidly bolted to the steel framework?

□

Is the bus phase designation from front to back, top to bottom and
left to right phase A, phase B, and phase C, respectively, when
viewed from the front of the switchgear?

□

Has the circuit phase rotation been checked in the bus-tie cubicle?

□

Are all bus connections tight?

□

Has any discoloration of current-carrying metal parts occurred?

□

Is it possible to draw a circuit breaker in or out while it is in the
closed position?

□

10.

If aluminum cable is used,

a. Have the outer strands of the conductor been scored or nicked
causing oxidation at the point of connection?

□

b. Are the cable terminator lugs designed for use on aluminum
cable?

□

11.

Have primary current-limiting fuses been provided for potential
transformers?

□

12.

Do the ammeter and voltmeter read correctly?

□

13.

Are the ammeter and voltmeter test blocks associated with the main
secondary circuit breaker wired correctly?

□

14.

Are there transit barriers or protective boots over primary studs for
each space cubicle?

□

15.

Are the cable connections made directly to the buses only for meter-
ing and/or control?

□

16.

Are all feeder conduits grounded within the substation?

□

17.

Are feeder cables adequately supported?

□

18.

Have feeder nameplates been installed on the switchgear?

□

19.

In the fire pump feeder circuit,

a. Is the circuit breaker overcurrent protective device set so as not
to open the circuit under stalled rotor current or other motor
starting conditions of the fire pump motor under maximum plant
load?

□

b. Does the circuit breaker overcurrent protective device (fuses are
not recommended) have overcurrent setting for short-circuit pro-
tection only (instantaneous trip without long- and short-time de-
lay)?

□

Figure 5-40 (continued)

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e) Cables: Low-voltage

1) Insulation-resistance tests

2) Continuity test

f) Metal-enclosed busway (See NEMA BUI. 1-1991 [B69])

1) Insulation-resistance test

2) Overpotential test, ac or dc

3) Phase-rotation and phase-cross voltage test

g) Air switches: High- and medium-voltage (See IEEE Std C37. 35-1976 [B38] and
IEEE Std C37.48-1987 [B41])

1) Insulation-resistance test

2) Overpotential test, ac or dc

3) Contact-resistance test

h) Air circuit breakers: Medium-voltage

1) Contact-resistance test

2) Minimum pickup voltage test on trip and close coils

3) Trip test from each protective device

4) Insulation-resistance tests, pole-to-pole and pole-to-ground

5) Insulation-resistance test on control wiring

6) Insulation power factor test on the bushings

7) Separate high-potential tests on magnetic breaker and on stationary gear

i) Oil circuit breakers: Medium-voltage

1) Contact-resistance tests

2) Contact time travel test, where appropriate

3) Insulating fluid tests: see item b4 in this subclause

4) Minimum pickup voltage tests on trip and close coils

5) Trip test from each protective device

6) Insulation-resistance test

7) Overpotential test, pole-to-pole and each pole-to-ground, ac or dc

8) Insulation-resistance test on appropriate control wiring

9) Insulation power factor test on poles and appropriate bushings, including deter-
mination of tank loss index

j) Power circuit breakers: Low voltage (see figure 5-41 )

1) Contact-resistance test

2) Insulation-resistance test

3) Minimum pick current by primary current injection

4) Long time delay by primary current injection at 300% pickup current

5) Short-time pickup and time delay by primary injection current

6) Instantaneous pickup by primary current

7) Trip unit reset characteristics verification

8) Set to engineer’s prescribed settings

9) Auxiliary protective device (such as ground-fault, undervoltage) operation
verification

k) Molded-case circuit breakers (see NEMA AB 4-1991 [B68])

1) Contact resistance tests

2) Time-current characteristics test

3) Instantaneous pickup current test

4) Insulation resistance tests, pole-to-pole, across pole, and pole-to-ground

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PLANT ENGINEERING SURVEY

LOW VOLTAGE POWER CIRCUIT BREAKER INSPECTION AND TEST RESULTS

Plant Location Date

Circuit Breaker Location

Circuit Description

Circuit Breaker Manufacturer Type

Manufacturer’s Serial Number or Shop Order Number

Trip Device Manufacturer Type

Sensor Rating Long-Time Delay Range

Short-Time Delay Range I 2 t

Instantaneous Range

Cable Size Ground Fault Range I'H

Fuse Manufacturer and Catalog Number

TEST RESULTS

Trip Unit

As Found
Settings per Phase

As Left

Settings per Phase

Long-Time Delay (amperes)

Short-Time Delay (amperes)

Instantaneous (amperes)

Test

Results

Long-Time Delay
Pickup (amperes)

Time (seconds)

Short-Time Delay
Pickup (amperes)

Time (seconds)

I 2 t In/Out

Instantaneous

Pickup (amperes)

Ground Fault

Pickup (amperes)

Time (seconds)

IH In/Out

Comments:

Figure 5-41 —Typical low-voltage power circuit breaker
inspection and test form

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l) Protective relays (see figure 5-42)

1) Insulation-resistance test on each circuit branch to frame (except electronic
solid-state)

2) Test for pickup parameters on each element. Make timing test at 2 points mini-
mum (3 points preferred) on time dial curve. Check for correct pickup current of
instantaneous element and target/seal-in units. Make other tests as required to
check operation of restraint, directional, and other elements.

3) Perform phase-angle and magnitude contribution tests on differential and
directional relays after energization to vectorially prove proper polarity and
connections.

m) Instrument transformers

1) Test transformer polarity electrically

2) Verify connection at secondary CT leads by driving a low current through the
leads and checking for this amount at applicable devices

3) Verify minimum grounding requirements as specified in NEC [BIO], Article 250

4) Confirm transformer ratio

5) Insulation-resistance test of transformer secondary and leads

6) Overpotential test primary insulation

7) Verify connection of secondary VT leads by applying a low voltage to the leads
and checking for this voltage at applicable devices

8) Check for VT secondary load with appropriate secondary voltage and current
measurements

n) Metering and instrumentation

1 ) Calibrate all meters at mid-scale

2) Determine relay pickup current by primary current injection

3) Verify all instrument multipliers

o) Ground-fault protection systems (see NEMA PB 2.2-1988 [B74])

1) Measure system neutral insulation resistance

2) Determine relay pickup current by primary injection

3) Test relay timing at 150% and 300% of pickup current

4) System operation test at 55% rated voltage

p) Grounding systems (see IEEE Std 142-1991 [B56])

1) Perform fall-of-potential test on main grounding electrode or system

2) Perform two-point method test or ground continuity test

q) Motor control centers (see NEMA ICS 2.3-1983 [B72])

1) Insulation-resistance test of each bus section, phase-to-phase and phase-to-
ground

2) Insulation-resistance test of each starter/controller section, with starter contacts
closed and protective device open

3) Continuity check of each control circuit

4) Test motor overload relays by primary current injection

5) Perform operational tests by initiating control devices

r) Rotating machinery (see NEMA MG 1-1993 [B73])

1 ) Large motors

i) Dielectric absorption test on motor and starter/controller circuit

ii) Determine motor winding polarization index

2) Small motors

i) Dielectric absorption test on motor winding

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PLANT ENGINEERING SURVEY
OVERCURRENT RELAY INSPECTION AND TEST RESULTS

Plant Location Date

Relay Location

Relay Description

Relay Type

Relay Manufacturer and Model No.

Current-Transformer Ratio Accuracy Voltage-Transformer Ratio Accuracy

Burden: Burden:

TEST RESULTS

Settings

Relay Tests

Tap

(amperes)

Time

Dial

Instan-

taneous

Pickup

(amperes)

Calibration

Current

(amperes)

j-i]

Target

(dc

amperes)

Specified

4X:

As Found

10X:

4X:

As Left

10X:

For Future Tests

Date

Seal-in holds at (dc amperes)

Comments:

Figure 5-42— Typical relay inspection and test form

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ii) The 30/60 s ratio shall be determined

3) Insulation-resistance test on pedestal, when applicable

4) Rotation test

5) Full-load and no-load current test

6) Observe proper operation and sequence of starters/controllers

7) Large motors: Perform vibration baseline test

8) Small motors: Perform vibration amplitude test

9) Check all protective devices

10) Overpotential test, winding to ground

s) Automatic transfer switches (see ANSI/NFPA 110-1993 [ B 13] and IEEE Std 446-
1987 [B58] )

1) Perform insulation-resistance tests

2) Set and calibrate voltage and frequency sensing, transfer time, and shutdown
relays

3) Perform automatic transfer by simulation loss of normal power and return to
normal power

4) Monitor and verify correct operation and timing of

i) Normal voltage and frequency sensing relays

ii) Engine start sequence

iii) Time delay upon transfer

iv) Alternate voltage and frequency sensing relays

v) Automatic transfer operation

vi) Interlocks

vii) Timing delay and retransfer upon normal power restoration

viii) Engine shutdown features

t) Battery and capacitor-stored control energy systems

1) Measure battery system charging voltage and individual cell voltages

2) Measure battery electrolyte specific gravity and level

3) Conduct battery discharge capacity tests

4) Test all capacitor trip devices according to manufacturers’ instructions

u) Surge arresters

1) Perform 60 Hz sparkover test

2) Perform radio influences voltage test

3) Perform insulation power factor test

4) Perform grounding continuity test to ground grid system

v) Outdoor bus structures

1) Insulation-resistance test

2) Overpotential test

3) Micro-ohmmeter test bus section joints

w) Turbine! engine generators (see ANSI/NFPA 1 10-1993 [B13] and IEEE Std 446-1987
[B58])

1) Dielectric absorption test on winding and determine polarization index

2) Phase rotation test

3) Protective relay tests (see protective relays)

4) Function test engine shutdown features, such as low oil pressure, coolant over-
temperature, over-speed, and over-cranking

5) Vibration baseline test

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6) Resistance load bank test

7) Perform load bank test

x) Systems function tests. Upon completion of equipment tests, systems function tests
shall be performed. Their intent is to prove the proper interaction of all sensing, pro-
cessing, and action devices that affect the design end results.

5.9.1 .4 Specific equipment testing

a) Direct-trip circuit breakers. Low-voltage air circuit breakers often are tripped
directly by the current flowing through them without the interposition of current
transformers and relays. Electromechanical trip devices usually are set at the factory;
to check them in the field requires a test source capable of supplying trip currents. If
they cannot be tested, there must at least be verification that the marked instantaneous
and time-delay settings are as required for coordination with other circuit breakers
and fuses.

Static electronic trip devices have adjustments that are easily set and tested at the job
site using a small compact test set designed for that purpose by the breaker manufac-
turer. The adjustments usually are factory set on their minimum settings; it is advis-
able, therefore, to set and calibrate the devices to their specified values. Record
settings (see typical form; figure 5-41).

b) Relay-operated circuit breakers. The relays should be checked in accordance with the
manufacturer’s instructions and with the general guide below, in which initial and
maintenance checks are compared. However, the actual performance of the relays in
service depends on the behavior of the instrument transformers that supply them with
current and potential. These, in turn, are influenced by the magnitude of their second-
ary burdens. Therefore, it is advisable to plan the testing in such a way as to obtain
information about the performance of the relays, wiring, and transformer together as
a unit as well as separately. Record the settings (see typical form; figure 5-42).

Figure 5-43 shows one phase of a typical current-transformer circuit, indicating four
different positions at which test current may be applied. The first three positions
cause current to flow either toward the relay only, toward the current transformer
only, or toward both in parallel. The test from Position 2 or 3 toward the current trans-
former only is a secondary impedance or excitation test, and should include at least
three points on the current-transformer saturation curve with one at or slightly above
the knee. One three-phase set of current transformers may differ widely in impedance
from another set, yet each may be satisfactory for its own function if the values are
consistent within the set.

1) Position 1. Test current applied at the individual relay location. At this point it is
possible to make three measurements, each of which is useful under certain con-
ditions. In order to show Position 1 in all three of its variations, an auxiliary cur-
rent transformer has been added. These auxiliary current transformers are often
used in multiple differentials and other complex schemes, but are rarely
employed in simple circuits like that shown in figure 5-40. In testing, they are
treated the same as any other current transformers.

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CHAPTER 5

PRIMARY

LEAD

■

■\ \

CURRENT / 0

TRANSFORMER /

TO OTHER
PHASES

Figure 5-43— Typical current-transformer circuit

i) The relay is disconnected, checked, and calibrated separately as an instru-
ment. Relays should be checked with a current standard and an accurate
timing device when they are placed in service, to make sure they have not
been damaged in shipment and that they operate in the desired time shown
by the coordination curves. If a relay does not give the desired operating
time for a given current on the predetermined time dial setting, the desired
time usually can be obtained by a minor adjustment of the time dial. Other
adjustments should not be attempted unless the adjuster is quite familiar
with relay design and performance or has specific manufacturer’s
instructions.

ii) With the relay disconnected and the main current-transformer primary
effectively open, the test current is applied to the remainder of the second-
ary circuit. The current drawn should be low until the voltage is raised to
the point where a main or auxiliary current transformer begins to saturate.
This test checks for defects in the secondary circuit, including current-
transformer excitation current, open circuits, short circuits, cross connec-
tions to other phases, etc.

If this test discloses appreciable differences in the test voltage required to
produce a given value of current in the various phases, the cause of these
differences needs to be discovered. The cause may be an open or short cir-
cuit in the secondary wiring, a defective current transformer, or a legitimate
unbalance of secondary burden caused, for example, by single-phase
metering or by the omission of a relay on one phase. It is not unusual to
find that the burden in the current transformer residual connection, includ-
ing ground relays, is much greater than in the phase leads. If the burden
appears excessive, tests should be conducted at Position 2.

iii) The test current is applied to the relay current terminals, with the secondary
wiring to the current transformers and other equipment normally con-
nected. The relay is subjected to the same tests as in Position 1 (i), including

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timing. Any difference in the results obtained is due to the fraction of cur-
rent used in the excitation of current transformers.

This test is of particular value, not only because it provides a measure of
the extent to which current-transformer performance affects relay pickup
and timing, but also because it is the basis of much maintenance testing. If
the values obtained in this position during later maintenance tests are sub-
stantially the same as those in the installation tests, the entire layout may be
assumed unchanged. Only if the tests in Positions 1 (ii) and l(iii) show
unexplained unbalances, definitely noticeable saturation, or questionable
residual burdens, are more extended tests necessary.

2) Position 2. Test current applied at switchboard terminals of current transformer
leads. The test current is applied to an entire phase group of relays, meters, aux-
iliary current transformers, etc. Since the main current transformers remain in
shunt with the burden, their effect on relay performance is included. This is a
convenient and fairly effective means of determining whether special relay cali-
brations are required.

In testing ground relays from Position 2, both phase- and ground-relay burdens
will be included, which is the condition that will exist in actual operation to
clear a ground-fault. The phase relays sometimes will be called upon to operate
on phase-to-phase faults (test current applied between two current-transformer
phase leads) and sometimes on three-phase faults (test current applied between
one current-transformer phase lead at a time and the neutral current level, with
the neutral burden jumpered out). If there is any significant difference in read-
ings, data should be recorded for both connections. The connections at
Position 2 may be opened to test the current transformers without burden other
than their leads to the panel. This is particularly advantageous in metal-clad
installations, where Positions 3 and 4 are inaccessible or difficult to reach.

3) Position 3. Test current applied at current-transformer secondary terminals. The
test current is applied across the secondary terminals of the current transformer
or across the secondary leads in the proximity of the current transformer, with
all meters, relays, and other burden normally connected and the primary open.
The testing is the same as Position 2, and the results are the same except that the
secondary leads are included with the burden in the same manner as in normal
service and that all devices can be readily identified with their respective current
transformers. If leads were not positively identified, this is important. The cur-
rent transformer can be tested alone from this position.

4) Position 4. Primary current check. This is the best method of checking the per-
formance of current transformers and relays together, since all burdens are
included along with their normal effect on the saturation characteristics of the
current transformer. Unfortunately, it is usually difficult to make the necessary
high-current connections to the primary circuit and the equipment required for
the high-current test source is unwieldy, so the primary current check is limited
to special applications. When a primary current check is made, both ratio and
polarity of the current transformers should be determined.

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CHAPTER 5

5.9.1. 5 Implementation of safeguards to prevent permanent magnetization of
current transformers

If during any of the above procedures the test current in the secondary winding of a current
transformer is abruptly interrupted, the current transformer core iron may become perma-
nently magnetized by residual flux to an extent determined by the current-transformer turns
ratio, the hysteresis characteristics of the core steel, and the magnitude of test current inter-
rupted in the current-transformer winding. Unremoved, this residual magnetism will signifi-
cantly affect the accuracy of the current transformers when they are placed back into service,
and may cause the connected relays to nuisance trip or otherwise operate unpredictably. This
misbehavior can be avoided by using a continuously variable current supply for any tests
involving current transformers in the connected circuits and instructing the operator to gradu-
ally reduce the test current from the test value to zero before opening the circuit to the test
power source. As an alternative, the tests can be performed with all current-transformer sec-
ondaries short-circuited and the test procedures modified accordingly.

5.9.1. 6 Final checking of equipment going into service

Once the usual high-potential and phasing checks have been completed, the equipment is
energized at normal potential for final check. Instrument transformer cases should have been
grounded with conductors of adequate size, and the secondary wiring grounded either solidly
or, if necessary, through well-designed spark gaps. With proper grounds in place, suitable test
switches, jacks, links, etc., installed, and with adequately insulated test leads, many users
change connections and make tests with the equipment energized. However, one has to make
certain that all the necessary auxiliary testing devices are present and that every step of the
testing procedure has been planned and closely examined in advance to guard against unfore-
seen hazards.

a) Current transformer secondary-circuit checks. All chances of connection, insertion,
and removal of meters, etc., should be made in such a manner that the secondary cir-
cuits of energized current transformers are not opened, even momentarily. An ener-
gized current transformer with an open secondary acts as a step-up transformer with a
ratio equal to the turns ratio, and thus dangerously high voltages are generated. All
current-transformer secondary circuits should therefore be provided with a test block
that requires the current transformer secondary terminals to be short-circuited before
the secondary circuit can be disconnected.

1) Null checks. If current is found where there should be none, a defect is indicated.
However, a null check is inconclusive and should be supplemented by an addi-
tional check that would detect a false null caused by an open or short circuit.

For differential circuits in which the operating coil normally has no current,
check that there is none. This, in conjunction with items 2 or 3 in this subclause,
verifies that the current transformer ratios are correctly balanced and the polari-
ties and phases correctly related.

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A zero or negligible current reading in the neutral or common return lead of a
three-phase set of current transformers under balanced-load conditions indicates
ratio balance and like polarity of the three secondaries.

2) Inspection of active relay circuits. Use an ammeter, voltmeter, wattmeter, or
phase-angle meter to check for the proper values and polarities of voltage and
current in the various relay circuits. Check the contact positions of directional
element and voltage relays and compare with those expected in view of load
conditions.

3) Relay operation checks with diverted load currents. Whenever any relay in ser-
vice is tested in a manner that may cause it to operate, the consequences of cir-
cuit breaker tripping must be considered. If a circuit breaker operation is not
permissible, the trip circuit of the relay being checked must be opened.

i) Differential relays. After determining that current is in the individual cur-
rent transformer circuits but none in the operating coil circuit, a current
may be caused to flow in the operating coil by temporarily short-circuiting
and disconnecting all but one of the current transformers.

The current from the remaining current transformer will check not only the
operating coil circuit but also the current transformer and its leads. This
should be done with each current transformer circuit in turn if they have not
been verified by other tests.

ii) Neutral or residual current relays. Short-circuit and disconnect the current
transformer leads of all but one phase. The remaining phase will supply
current to the relay.

b) Voltage (potential) transformer secondary circuit checks. Measure the voltages
applied to all relay potential coils. If any are inadequate, investigate. Look for blown
fuses, short circuits, excessive burdens, and improperly adjusted potential devices.

Check the voltage (potential) transformer and phase to which each relay potential ter-
minal is connected by removing one potential fuse at a time (at the voltage trans-
former secondary terminals) and noting the effect on the voltage applied to the relay.

1) Ground-fault voltage relays and elements. Voltage relays, or relay elements, that
are connected in one corner of a voltage transformer secondary broken-delta
connection have no voltage across them in the absence of a ground fault. Such a
fault can be simulated as follows:

i) By de-energizing the equipment so that it is safe to work on;

ii) By disconnecting the phase lead from one voltage transformer primary ter-
minal and fastening this lead where it can safely be re-energized;

iii) By short-circuiting the vacated primary terminal to its neutral terminal;

iv) By re-energizing the equipment, reading voltages, and observing relay
operation;

v) By returning connection to normal and re-energizing the equipment.

2) Ground-fault directional relays. These have polarizing windings, either a cur-
rent winding energized from a current transformer in the equipment neutral-to-

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ground connection or potential windings energized from one corner of a broken-
delta-connected set of voltage transformers, the same as the preceding type, and
their operating current windings energized from the common (neutral or resid-
ual) connection of a set of current transformers. These relays should be checked
with diverted load currents as follows:

i) By determining the direction of power flow;

ii) By altering one phase of the voltage transformer primary as described in
items liiand liii;

iii) By short-circuiting and disconnecting the current transformer leads of this
same phase. This should cause the ground-fault directional relay to indicate
a direction of power flow that is the reverse of that actually existing in the
line; that is, if the power flows toward the bus, the relay contacts should
close to trip;

iv) By restoring the current-transformer leads and removing their short circuit.
Then short-circuiting and removing the current-transformer leads of the
other phases. This should cause the relay to indicate a direction of power
flow that is the same as that actually in the line;

v) By restoring all connections to normal.

c) Stage system test at normal or reduced system voltage. This method causes no diffi-
culties with automatic throw-over devices and is the best method of testing them.
Nearly all other system tests require setting up staged faults, which are the last resort
in testing. The faults are applied to the system at carefully chosen times and places,
under controlled and back-up protected conditions, and the action of relays and
other equipment is recorded and analyzed. Such tests are seldom used and can only
be justified under the following conditions:

1) The scheme is intricate, new, or unfamiliar;

2) The wiring is complicated or inaccessible;

3) The relay response characteristics are believed to be so critical that the use of
normal or diverted load currents would introduce intolerable phase-angle errors;

4) The scheme has shown otherwise unexplainable misbehavior;

5) The power system is so complex that performance of protective devices cannot
be accurately predicted.

A staged fault test should be approved only when no other method of testing will suf-
fice. The plan should be scrutinized from every conceivable safety consideration, and
all parties who could possibly be affected should be notified.

5.9.2 Maintenance [B64]

For dependable performance of protective devices, regular and systematic inspection and
maintenance are essential. The three basic reasons for systematic maintenance are safety, reli-
ability, and economy: safety of personnel and of plant and equipment, reliability of service,
and economy in the reduction of major repairs and in the reduction of power loss.

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Regarding safety, a survey by Factory Mutual Research indicates that approximately one of
every five industrial fires is of electrical origin and that about one-half of these are due to lack
of adequate maintenance.

Regarding economy, systematic preventive maintenance will result in protective devices that
stand ready to prevent costly destruction and loss of electrical equipment during abnormal
conditions, with the resulting downtime and loss of production until repairs and replacement
are completed.

5.9.2. 1 General maintenance

(See also ANSI/NFPA 70B-1990 [B 11].) A regularly scheduled preventive maintenance pro-
gram is the most important factor in keeping protective devices in dependable operating con-
dition. Periodic inspection and suitable records will indicate what maintenance is advisable
and whether or not it should be performed immediately or may be safely deferred until the
next inspection period.

The intervals between inspections should be determined by the mechanical design of the pro-
tective devices and by local operating and atmospheric conditions. Where dust is rapidly
deposited within equipment or where condensation may occur, the inspection and cleaning
operations should be frequent. Condensation can be very serious and, when detected, steps
should be taken to remove the cause, or heaters should be installed to keep the equipment dry.
Combination switching and protective devices have a limited safe life cycle which is closely
related to the number of times they operate. This fact is important in the consideration of the
inspection and maintenance program. The required frequency of inspection, maintenance,
and tests varies for different industries and local conditions.

Inspections should be made by competent and experienced personnel who are familiar with
the manufacturer’s instructions for each device. They should be equipped with necessary
instruments, gauges, tools, and other test equipment, and should be skilled in their use.
Inspection and test records are necessary documents. They are useful guides in determining
the frequency of required maintenance.

5.9.2.2 General precautions

(See also ANSI/NFPA 70E-1988 [B 12].) Do not work on or around live parts. If emergencies
require that work be done on live parts, it should be done only by personnel experienced in
working equipment “hot.” Rubber gloves with leather protector, safety glasses, and other pro-
tective equipment must be used.

Extreme care must be exercised at all times. All circuits should be considered alive until per-
sonnel expecting to work on them assure themselves personally that they are de-energized.
Every possible precaution should be taken to assure that the circuit will not be energized
while maintenance personnel are working on it. It is recommended that switching devices
isolating the circuit be padlocked in the open position and personnel working on the circuit
retain the key until the circuit is cleared. On high-voltage circuits that are de-energized,
proper grounding methods should be used within view of the maintenance personnel.

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5.9.2.3 Replacement and spare parts

An adequate supply of repair parts should be kept in stock for all units. These usually are
listed in the manufacturer’s instructions. Replacement fuses of the correct type and rating
should be available when needed. Fuses of a larger size, having less current-limiting ability, or
having an interrupting rating less than required for the application, should never be substituted
for a fuse of the correct size and type. Always de-energize the circuit before replacing a fuse.

5.9.2.4 Fuses

It is recommended that a visual inspection of fuses be made annually, unless experience indi-
cates that more frequent checks are necessary. The following steps are recommended:

a) First de-energize the equipment.

b) Check all fuses to assure that the correct rating and type are installed. Where renew-
able fuses are used, the fuse links should be examined to assure that the correct link is
installed; however, the use of renewable fuses is not recommended. It is recom-
mended that renewable fuses be replaced with fuses having correct current rating,
adequate interrupting rating, and proper time-delay characteristics.

c) Look for evidence of overheating of cartridge fuses. Replace fuses having discolored
or weakened casings and determine and correct the cause of the overheating. Where
fuse clips have lost their tension, they should be replaced with new clips, and suitable
clamps should be installed to provide good contact. Where the ferrules or knife
blades of cartridge fuses are corroded or oxidized, the contact surfaces should be
cleaned and polished. Silver-plated contact surfaces should not be abraded. Wiping
surfaces with a noncorrosive cleaning agent is suggested.

d) Look for fuses that have been bridged with wire, metal strips, disks, etc. Replace with
correct fuses and take the necessary action to prevent a recurrence.

e) Check terminals to assure that all connections are tight. Where there is discoloration
or other evidence of heating, the connecting surfaces should be cleaned and polished.
Silver-plated surfaces should not be abraded. Aluminum parts that show deterioration
should be replaced.

f) Check enclosure to assure that the equipment is protected and that easily ignitable
materials are excluded. Check that covers are in place and fastened. In hazardous
locations, assure that fuses are installed in an appropriate explosion-proof enclosure
with the required gaskets and seals intact.

5.9.2.5 Enclosed switches

It is recommended that a visual inspection of enclosed switches be made annually, unless
experience indicates that more frequent checks are necessary. The following steps are recom-
mended as may be required.

a) De-energize the equipment.

b) Thoroughly clean all parts, inside and outside. Lubricate operating mechanism and
sliding contact surfaces if required.

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c) Check contacts for alignment and adjustment. Clean and dress blades if required.
Many contact surfaces, such as arcing contacts, are silver tungsten or other types of
materials that must never be dressed. When contacts of these materials require main-
tenance, they must be replaced. If contact clips have lost their tension, replace clips
or replace the switch.

d) Check that connections of blades to insulating bar are tight. Check that rod for exter-
nal operation is attached to insulating bar. Check that spring for snap action is operat-
ing correctly. Where parts are damaged, they should be replaced or a new switch
installed. Check the door interlock for proper operation.

e) Check terminals to assure that all connections are tight. Where there is discoloration
or other evidence of heating, the connecting surfaces should be cleaned and polished.
Before returning to service, determine the cause of heating and correct as required.
Silver-plated surfaces should not be abraded. Aluminum parts that show deterioration
should be replaced.

f) Check enclosures to assure that they are clean, that switch is protected, and that eas-
ily ignitable materials are excluded. Check that covers are in place and fastened. In
hazardous locations, ensure that switches are installed in appropriate explosion-proof
enclosures and the conduit from the switch enclosure is properly sealed.

5.9.2.6 Molded-case circuit breakers

It is recommended that a visual inspection be made annually, unless experience indicates that
more frequent checks are necessary. Most molded-case circuit breakers are factory calibrated
and the covers sealed. This seal should not be broken as it may void the warranty. It is recom-
mended that molded-case circuit breakers be tested before being placed in service by passing
sufficient current through them to cause them to trip. If a molded-case circuit breaker is found
to be defective, it is recommended that it be replaced and not repaired.

For the annual visual inspection, the following steps are recommended:

a) De-energize the equipment.

b) Look for external evidence of damage or overheating. If found, replace unit involved
and correct source of trouble.

c) Check terminals to assure that all connections are tight. Where there is discoloration
or other evidence of heating, the connecting surfaces should be cleaned and polished.
Silver-plated surfaces should not be abraded. Aluminum parts that show deterioration
should be replaced.

d) Open and close the circuit breaker several times in order to exercise the mechanism
and the contacts.

e) Where installed in enclosures, assure that enclosures are clean and provide the
required protection. Check that covers are in place and fastened and test any door
safety interlocks for correct operation. In hazardous locations, ensure that circuit
breakers are installed in appropriate explosion-proof enclosures and the conduit from
the circuit-breaker enclosure is properly sealed.

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If a comprehensive thorough maintenance inspection is justified by severe duty or
environment, or if a higher degree of reliability is required, the following procedures are
recommended:

a) With line and load terminals completely disconnected, check the insulation resistance
between phases of opposite polarity and phase to ground with a megohmmeter. The
voltage used for this test should be at least 50% greater than the circuit-breaker rat-
ing; however, a minimum of 500 V is permissible. Also, check the resistance between
the line and load terminals with the circuit breaker open. If the resistance values are
below 1 MQ, the circuit breaker should be removed and returned to the manufacturer
for repair or replacement.

b) With line and load terminals completely disconnected, make a dc millivolt drop test
from line to load terminals of each circuit breaker. It is recommended that this test be
made at a nominal dc voltage and a practical value (50-100%) of rated current. The
manufacturer can furnish the acceptable ranges for millivolt drop tests.

c) With an ammeter in the circuit, apply a current of approximately 300% of the circuit-
breaker rating to each pole to assure that the circuit breaker will trip automatically.
Should the circuit breaker fail to trip, it should be returned to the manufacturer for
repair or replacement.

d) With an ammeter in the circuit, apply a current of approximately 200% of the
instantaneous magnetic trip pickup value to assure that the magnetic trip device is
operating.

e) Mechanical operation should be checked by moving the operating handle to the ON
and OFF positions several times. This step is most important.

5.9.2.7 Low-voltage power circuit breakers

It is recommended that a visual inspection be made annually, unless experience indicates that
more frequent checks are necessary. It is recommended that a complete inspection and main-
tenance, if required, be made at two-year intervals.

At the annual visual inspection, the following steps are recommended:

a) De-energize the equipment.

b) Look for evidence of damage or overheating. If found, repair or replace the parts
involved and correct the source of trouble.

c) Check terminals to assure that all connections are tight. Where there is discoloration
or other evidence of heating, the connecting surfaces should be cleaned and polished.
Before returning to service, determine the cause of heating and correct as required.
Silver-plated surfaces should not be abraded. Aluminum connections that show dete-
rioration should be replaced.

d) Open and close the circuit breaker several times to exercise the mechanism and
contacts.

e) Check enclosure to assure that enclosures are clean and that the proper degree of pro-
tection is provided.

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At the two-year inspection, the following additional steps are recommended, using the manu-
facturer’s instructions:

a) Remove arc chutes and examine for burning. Clean or replace when necessary.

b) Check contact alignment and pressure. Adjust to manufacturer’s recommendation, if
required.

c) For draw-out equipment, check the alignment and pressure of the primary and sec-
ondary disconnecting device contact fingers.

d) Check the settings of automatic tripping units and check their operation by moving
the trip armatures to trip the circuit breaker.

e) For electrically operated circuit breakers, check the reliability of the control power
source.

f) Check that latches and triggers are properly adjusted and that the latch bite is in
accordance with manufacturer’s recommendation.

g) If there are flexible shunts, see that they are in good condition and that connections
are tight.

h) Check pins, bolts, nuts, and general hardware, and tighten where necessary.

i) Check auxiliary switches to see that contacts are in good condition and that operating
links are properly adjusted.

j) Check mechanical interlocks that prevent withdrawing or inserting a circuit breaker
while it is closed.

k) Check control wiring for loose connections.

l) Thoroughly clean all parts and lubricate in accordance with manufacturer’s
instructions.

At two- or three-year intervals it is recommended that the calibration of overcurrent devices
be tested and adjusted. This test should be done by personnel experienced in this work who
have been well trained and who have the necessary test equipment. Where adverse environ-
mental conditions exist or where operating of the equipment is frequent, testing annually may
be required. Arrangements for these tests may be made with consulting engineers, manufac-
turers, or testing laboratories. In large industrial plants, staffing of trained personnel and the
purchase of test equipment may be justified as a part of the plant maintenance facilities.

5.9.2.8 Protective relays

It is recommended that protective relays be inspected annually, unless experience indicates
that more frequent inspection is necessary. They should be serviced in accordance with the
manufacturer’s instructions to ensure accuracy and reliability. The following general proce-
dures are recommended:

a) Relays should be clean and free from friction.

b) Contacts should be maintained and properly aligned.

c) All leads and terminal hardware should be tight.

d) All application requirements should be observed.

e) Relay settings should be verified for conformance with the recommendations of the
protective device coordination study.

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f) Relays should be calibrated and tested for accuracy in accordance with the manufac-
turers’ recommendations. Test intervals should be two years or as job experience
dictates.

5.9.2.9 Motor-control equipment

It is recommended that motor-control equipment be inspected and cleaned at six-month inter-
vals. Where motors are started many times a day, it may be necessary to inspect and clean at
more frequent intervals. The required frequency varies in proportion to the rate of motor
starts and upon local atmospheric conditions. It is recommended that a complete inspection
be made annually. For the six-month inspection, the following steps are recommended:

a) De-energize the equipment.

b) Thoroughly clean all parts, tighten all connections, and lubricate if required.

c) Inspect contacts and arcing tips and, if rough, replace. Since contacts operate in sets,
replacement should be made in sets. The extra time and expense spent in replacing
the set will be repaid in contact life. Do not file contacts.

d) Examine arc chutes for burning and replace if required (medium-voltage starters).

f) Motor overload relays should be checked to ensure that the correct heaters are
installed. The overload relay reset should be checked to see that it is correctly set for
manual or automatic reset.

g) Check enclosure to assure that the proper degree of protection is provided. Check that
covers are in place and fastened, and test any door safety interlocks for correct opera-
tion. In hazardous locations, ensure that controllers are installed in explosion-proof
enclosures and the conduit from the motor controller is properly sealed.

5.9.2.10 Switchgear assemblies and motor-control centers

It is recommended that switchboards, switchgear assemblies, and motor control centers be
inspected and cleaned annually, unless experience indicates that more frequent inspection is
required. The following steps are recommended:

a) Assure that all circuits are de-energized and locked out in accordance with lock and
tag procedures.

b) Assure that the area around the assembly is kept clean and free of combustibles at all
times. This should be part of the day-to-day maintenance.

c) Inspect buses and connections to be sure that all connections are tight. Look for
abnormal conditions that might indicate overheating or weakened insulation. Infrared
testing can identify hot-spots caused by loose connections without de-energizing the
equipment.

d) Remove dust and dirt accumulations from bus supports and enclosure surfaces. Use
of a vacuum cleaner with a long nozzle is recommended to assist in this cleaning

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operation. Wipe all bus supports clean with a cloth moistened in a non-toxic cleaning
solution. (Refer to manufacturer’s instructions for recommended solvent.) Do not use
abrasive material for cleaning plated surfaces, since the plating will be removed.

e) The internal components should be maintained according to the specific instructions
supplied for each device.

f) Secondary wiring connections should be checked to be sure they are tight.

5.9.2.11 Instrument transformers and wiring

Inspect equipment visually for obvious defects such as broken studs, loosened nuts, damaged
insulation, etc.

The indication of normal potential at the relay by lamp or voltmeter is considered adequate
verification for voltage transformers and circuits. If the combined relay and current trans-
former check made at installation is repeated and substantially the same results are obtained,
this is sufficient proof that there is no short circuit in the current transformer or its leads. A
check under load with a low-burden ammeter in series or shunt with the relay will establish
proof of continuity. More elaborate checking may be required if there has been any change in
the equipment or wiring or if a change in setting materially alters the current or potential
transformer burdens. If there is evidence of improper performance, the equipment must be
completely de-energized, the protective ground connections removed, and the insulation of
the current, potential, and control wiring tested.

5.9.2.12 Control wiring and operation

Periodic testing of protective equipment must ensure that the operation of any tripping relay
will result in the circuit breaker being tripped. After all terminals and exposed portions of the
trip circuit wiring and the condition and adjustment of any circuit breaker auxiliary switches
in the trip circuit have been visually checked, the relay trip contacts should be manually
closed to simulate an actual trip operation. Where there are too many relays to trip the circuit
breaker from each, the trip circuit can normally be tested through at least one relay that is
connected with the others to a common point on the opening control circuit wire. A record
should be kept of each relay from which the circuit breaker was tripped, so that all relays
may, in turn, be covered during successive tests.

5.9.2.13 Completing the job

Before re-energizing the protective system, a visual inspection by at least two qualified per-
sons should be made to ascertain that all temporary ground connections are removed and that
all tools, rags, and other cleaning aids have been removed from the interior of switchgear and
unit substations.

5.9.2.14 Special maintenance

Following interruption of a fault, certain equipment may require special maintenance. Refer
to the equipment manufacturers’ instructions for special directions.

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5.9.3 Records

Keep complete records for each unit of electrical equipment. These should include manufac-
turers’ instruction bulletins and repair part bulletins. They will be extremely helpful in emer-
gencies to quickly identify parts and secure replacements needed to make repairs.

Properly recorded data will indicate when repairs may be anticipated. Records should show
nameplate data, ratings, date of installation, etc. Reference drawings, manufacturers’ instruc-
tions, and spare part data should be recorded. The dates of each inspection and a record of all
tests and maintenance should be included.

5.10 Bibliography

[B 1 ] Accredited Standards Committee C2-1993, National Electrical Safety Code.

[B2] AIEE Committee Report, “Bibliography of Industrial System Coordination and Pro-
tection Literature,’’ IEEE Transactions on Applications and Industry, vol. 82, pp. 1-2, Mar.
1963.

[B3] Ananian, L. G., and Colvin, F. L., “The Industrial Electrical Engineer’s Responsibilities
and How They Reflect on Management,” IEEE Transactions on Industry and General Appli-
cations, vol. IGA-7, pp. 169-177, Mar./Apr. 1971.

[B4] ANSI C37. 6-1971, American National Standard Schedules of Preferred Ratings for AC
High-Voltage Circuit Breakers Rated on a Total Current Basis.

[B5] ANSI C37.42-1989, American National Standard for Switchgear— Distribution Cutouts
and Fuse Links.

[B6] ANSI C37. 46-1981 (Reaff 1987), American National Standard Specifications for Power
Fuses and Fuse Disconnecting Switches.

[B7 ] ANSI C37.47-1981 (Reaff 1988), American National Standard Specifications for Distri-
bution Fuse Disconnecting Switches, Fuse Supports, and Current-Limiting Fuses.

[B8] ANSI C50. 10-1990, American National Standard for Rotating Electrical Machinery—
Synchronous Machines.

[B9] ANSI C50. 13-1989, American National Standard for Rotating Electrical Machinery-
Cylindrical Rotor Synchronous Generators.

[BIO] ANSI/NFPA 70-1993, National Electrical Code.

[Bll| ANSI/NFPA 70B-1990, Electrical Equipment Maintenance.

[B12] ANSI/NFPA 70E-1988, Electrical Safety Requirements for Employee Workplaces.

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Std 141-1993

[B13J ANSI/NFPA 110-1993, Emergency and Standby Power Systems.

[B 1 4 1 ANSI/UL 198B-1987, Safety Standard for Class H Fuses.

[B15J ANSI/UL 198C-1986, Safety Standard for High-Interrupting Capacity Fuses, Current-
Limiting Types.

[B16] ANSI/UL 198D-1987, Safety Standard Class K Fuses.

[B 17] ANSI/UL 198E-1987, Safety Standard Class R Fuses.

[B18J [ANSI/UL 198F-1987, Safety Standard for Plug Fuses.

[B 1 9] ANSI/UL 198G-1987, Safety Standard for Fuses for Supplementary Overcurrent Pro-
tection.

[B20] ANSI/UL 845-1987, Safety Standard for Motor Control Centers.

[B21] ANSI/UL 891-1984, Safety Standard for Dead-Front Switchboards.

[B22] Baker, D. S., “Generator Backup Overcurrent Protection,’’ IEEE Transactions on
Industry Applications, vol. IA-18, pp. 632-640, Nov./Dec. 1982.

[B23] Blackburn, J. L., Protective Relaying. New York: Marcel Dekker, Inc., 1987.

[B24] Bridger, B., Jr., “High-Resistance Grounding,’’ IEEE Transactions on Industry Appli-
cations, vol. IA-19, pp. 14-20, Jan./Feb. 1983.

[B25] Cable, B. W., Powell, L. J., and Smith, R. L., “Application Criteria for High-Speed Bus
Differential Protection,” IEEE Transactions on Industry Applications, vol. IA-19, pp. 619-
624, July/Aug. 1983.

[B26] Castenschiold, R., “Solutions to Industrial and Commercial Needs Using Multiple
Utility Services and Emergency Generator Sets,” IEEE Transactions on Industry Applica-
tions, vol. IA-10, pp. 205-208, Mar./Apr. 1974.

[B27] Conrad, R. R., and Dalasta, D. A., “New Ground-fault Protective System for Electrical
Distribution Circuits,” IEEE Transactions on Industry and General Applications, vol. IGA-3,
pp. 217-227, May/June 1967.

[B28] Cummings, P. G., Dunki-Jacobs, J. R., and Kerr, R. H., “Protection of Induction
Motors Against Unbalanced Voltage Operation,” IEEE Transactions on Industry Applica-
tions, vol. IA-21, pp. 778-792, May/June 1985.

[B29] GET-6098, The Impact of Arcing Ground Faults on Low- Voltage Power System
Design, General Electric Co., Dec. 1970.

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[B30] Goff. L. E., Rook, M. J., and Powell, L. J., “Pilot Wire Relay Applications in Industrial
Plants Utilizing a New Static Pilot Wire Relay,” IEEE Transactions on Industry Applications,
vol. IA-16, pp. 395-404, May/June 1980.

[ B 31] Harder, E. L., Klemmer, E. H., Sonnemann, W. K., and Wentz, E. C., “Linear Couplers
for Bus Protection,” AIEE Transactions, vol. 61, pp. 241-248, May 1942.

[B32] Hoeingman, W. F., “Surge Protection for AC Motors: When Are Protective Devices
Required?” IEEE Transactions on Industry Applications, vol. 1A-19, pp. 836-843, Sept./Oct.
1983.

[B33] IEEE Committee Report, “Coordination of Lightning Arresters and Current-Limiting
Fuses,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-91, pp. 1075-1078,
May/June 1972.

[B34] IEEE Committee Report, “The Impact of Sine-Wave Distortions on Protective Relays,”
IEEE Transactions on Industry Applications, vol. IA-20, pp. 335-343, Jan./Feb. 1984.

[B35] IEEE Std C37. 2-1991, IEEE Standard Electrical Power System Device Function Num-
bers (ANSI).

[B36] IEEE Std C37. 13-1990, IEEE Standard Low- Voltage AC Power Circuit Breakers Used
in Enclosures (ANSI).

[B37] IEEE Std C37.20.1-1987 (Reaff 1992), IEEE Standard for Metal-Enclosed Low-
Voltage Power Circuit Breaker Switchgear (ANSI).

[B38] IEEE Std C37. 35-1976 (Reaff 1992), IEEE Guide for the Application, Operation, and
Maintenance of High-Voltage Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse
Disconnecting Switches, and Accessories (ANSI).

[B39] IEEE Std C37.40-1981 (Reaff 1987), IEEE Standard Service Conditions and Defini-
tions for High-Voltage Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Discon-
necting Switches, and Accessories (ANSI).

[B40] IEEE Std C37.41-1988, IEEE Standard Design Tests for High-Voltage Fuses, Distribu-
tion Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and Accessories
(ANSI).

[B41 1 IEEE Std C37.48-1987 (Reaff 1992), IEEE Guide for Applications, Operation, and
Maintenance of High-Voltage Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse
Disconnecting Switches, and Accessories (ANSI).

[B42] IEEE Std C37.90-1989, IEEE Standard Relays and Relay Systems Associated with
Electric Power Apparatus (ANSI).

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[B43] IEEE Std C37. 91-1985 (Reaff 1991), IEEE Guide for Protective Relay Applications to
Power Transformers (ANSI).

[B44] IEEE Std C37.96-1988, IEEE Guide for AC Motor Protection (ANSI).

[B45] IEEE Std C57. 12.00-1987, IEEE Standard General Requirements for Liquid-
Immersed Distribution, Power, and Regulating Transformers (ANSI).

[B46] IEEE Std C57. 12.58-1991, IEEE Guide for Conducting a Transient Voltage Analysis
of a Dry-Type Transformer Coil.

[B47] IEEE Std C57. 12.59-1989, IEEE Guide for Dry-Type Transformers Through-Fault
Current Duration (ANSI).

[B48] IEEE Std C57. 13-1978 (Reaff 1986), IEEE Standard Requirements for Instrument
Transformers (ANSI).

[B49] IEEE Std C57. 94-1982 (Reaff 1987), IEEE Recommended Practice for Installation.
Application, Operation, and Maintenance of Dry-Type General Purpose Distribution and
Power Transformers (ANSI).

[B50] IEEE Std C57. 106-1991, IEEE Guide for Acceptance and Maintenance of Insulating
Oil in Equipment.

[B51] IEEE Std C57. 109-1993, IEEE Guide for Liquid-Immersed Transformer Through-
Fault-Current Duration. 1

[B52] IEEE Std C57. 1 11-1989, IEEE Guide for Acceptance of Silicone Insulating Fluid and
Its Maintenance in Transformers.

[B53] IEEE Std C57. 121-1988, IEEE Guide for Acceptance and Maintenance of Less Flam-
mable Hydrocarbon Fluid in Transformers (ANSI).

[B54J IEEE Std C62. 2-1987, IEEE Guide for the Application of Gapped Silicon-Carbide
Surge Arresters for Alternating-Current Systems (ANSI).

[B55] IEEE Std 100-1992, The New IEEE Standard Dictionary of Electrical and Electronics
Terms (ANSI).

[B56J IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and
Commercial Power Systems (IEEE Green Book) (ANSI).

[B57] IEEE Std 242-1986 (Reaff 1991), IEEE Recommended Practice for Protection of
Coordination of Industrial and Commercial Power Systems (IEEE Buff Book) (ANSI).

[B58] IEEE Std 446-1987, IEEE Recommended Practice for Emergency and Standby Power
Systems for Industrial and Commercial Applications (IEEE Orange Book) (ANSI).

1 Some citations in this chapter refer to the 1985 edition of this standard.

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[B59] IEEE Std 1001-1988, IEEE Guide for Interfacing Dispersed Storage and Generating
Facilities with Electric Utility Systems (ANSI).

[B60] Krick, J. B., and Potts, C. D., “Dynamic Fault Testing of Ground Sensing Relays,”
IEEE Transactions on Industry Applications, vol. IA-19, pp. 975-979, Nov./Dec. 1983.

[B61 J Larner, R. A., and Gruesen, K. R., “Fuse Protection of High-Voltage Power Transform-
ers,” AIEE Transactions (Power Apparatus and Systems ), pt. Ill, vol. 78, pp. 864-878, Oct.
1959.

[B62] Langhans, J. D., and Ronat, A. E., “Protective Devices Coordination via Computer
Graphics,” IEEE Transactions on Industry Applications, vol. IA-16, pp. 404-441, May/June
1980.

[B63] Lathrop, C. M., and Schleckser, C. E., “Protective Relaying on Industrial Power Sys-
tems,” AIEE Transactions, pt. II, vol. 70, pp. 1341-1345, 1951.

[B64] Maintenance Testing Specifications for Electric Power Distribution Equipment and
Systems, International Electrical Testing Association, Morrison, CO, 1993.

[B65] Mason, C. R., The Art and Science of Protective Relaying. New York: Wiley, 1956.

[B66] Mathur, B. K., “Service Supply-Line Protection— An Industrial Plant User’s View,
IEEE Transactions on Industry Applications, vol. IA-19, pp. 9-14, Jan./Feb. 1983.

[B67] McFadden, R. H., “Power-System Analysis: What It Can Do For Industrial Plants,”
IEEE Transactions on Industry and General Applications, vol. IGA-7, pp. 181-188, Mar./
Apr. 1971.

|B68] NEMA AB 4-1991, Guidelines for Inspection and Preventative Maintenance of
Molded-Case Circuit Breakers Used in Commercial and Industrial Applications.

[B69] NEMA BU 1.1-1991, Generals Instructions for Proper Handling, Installation, Opera-
tion, and Maintenance of Busway Rated 600 Volts or Less.

[B70] NEMA FU 1-1986, Low- Voltage Cartridge Fuses.

[B71] NEMA ICS 1-1988, General Standards for Industrial Control and Systems (partially
revised by NEMA ICS 1-1992).

[B72] NEMA ICS 2.3-1983, Instructions for Handling, Installation, Operation, and Mainte-
nance of Motor Control Centers.

[B73] NEMA MG 1-1993, Motors and Generators

[B74J NEMA PB 2.2-1988, Application Guide for Ground Fault Protective Devices for
Equipment.

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[B75] NETA ATS-1990, Acceptance Testing Specifications (International Electrical Testing
Association, Inc.).

[B76] Potochney, G. J., and Powell, L. J., “Application of Protective Relays on a Large Indus-
trial-Utility Tie with Industrial Cogeneration,” IEEE Transactions on Industry Applications,
vol. IA-19, pp. 461-469, May/June 1983.

[B77] Powell, L. J., “An Industrial View of Utility Cogeneration Protection Requirements,”
IEEE Transactions on Industry Applications, vol. IA-24, pp. 75-81, Jan./Feb. 1988.

[B78] Shields, F. J., “The Problem of Arcing Faults in Low-Voltage Power Distribution Sys-
tems,” IEEE Transactions on Industry and General Applications, vol. IGA-3, pp. 15-25, Jan./
Feb. 1967.

[B79] St. Pierre, C. R., “Loss-of-Excitation Protection for Synchronous Generators on Iso-
lated Systems,” IEEE Transactions on Industry Applications, vol. IA-21, pp. 81-98, Jan./Feb.
1985.

[B80] St. Pierre, C. R., and Wolny, T. E., “Standardization of Benchmarks for Protective
Device Time-Current Curves,” IEEE Transactions on Industry Applications, vol. IA-22,
pp. 623-633, July/Aug. 1986.

[ B 8 1 J Weddendorf, W. A., “Evidence of Need for Improved Coordination and Protection of
Industrial Power Systems,” IEEE Transactions on Industry and General Applications, vol.
IGA-1, pp. 393-396, Nov./Dec. 1965.

[B82] Wu, A. Y., “The Analysis of Current Transformers Transient Response and Its Effect on
Current Relay Performance.” IEEE Transactions on Industry Applications, vol. IA-21,
pp. 793-802, May/June 1985.

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310

Chapter 6

Surge voltage protection

6.1 Nature of the problem

Transient overvoltages are due to natural and inherent characteristics of power systems. Over-
voltages may be generated by lightning or by a sudden change of system conditions (such as
switching operations, faults, load rejection, etc.), or both. Broadly, the overvoltage types are
normally classified as lightning-generated and all others as switching-generated. The magni-
tude of these overvoltages can be above maximum permissible levels and therefore need to be
reduced and protected against if damage to equipment and possible undesirable system per-
formance are to be avoided.

A direct lightning stroke current surge will have the form of a steep front wave that will travel
away from the stricken point in both directions along the power system conductors (figure
6-1). As the surge travels along the conductors, losses cause the magnitude of the voltage
surge to constantly diminish. If the voltage magnitude is sufficient to produce corona, the
decay of the voltage surge will be fairly rapid until below the corona starting voltage. Beyond
this point the decay will be more deliberate. Properly rated surge arresters at the plant termi-
nal of the incoming lines will generally reduce the overvoltage to a level the terminal station
apparatus can withstand.

Figure 6-1 —Two traveling bodies of charge result when a quantity
of charge is deposited on conducting line by lightning

In instances where the local industrial plant system is without lightning exposure, except
from the exposed high-voltage lines through step-down transformers effectively protected
with high-side surge arresters, lightning surges are likely to be quite moderate. Likewise,
surges due to switching phenomena, although more common, are generally not as severe.
Only occasionally would line-to-ground potentials on the local system reach arrester-
protective levels. The large number of radiating cable circuits with their array of connected
apparatus acts to greatly curb the slope and magnitude of the voltage surge that reaches any
particular item of connected apparatus. However, transformers and other equipment items
connected as a single load at the end of circuits are particularly vulnerable. Experience has
indicated that certain types of apparatus are susceptible to voltage surges for almost any
circuit connection arrangement, and it is advisable to fully investigate the possibility of
damaging voltage surges.

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The occurrence of abnormal applied voltage stresses, either transient, short-time, or sustained
steady-state, contributes to premature insulation failure. Electrical organic insulation deterio-
ration to the point of failure results from an aggregate accumulation of insulation damage that
finally reaches the critical stage, in which a conducting path is rapidly driven through the
insulation sheath and failure (short circuit) takes place. Large amounts of current may then be
driven through the faulted channel, producing large amounts of heat. An excessive increase in
temperature results, which rapidly expands the zone of insulation damage, and complete
destruction occurs rather quickly unless the supply of electric current is interrupted. Some
insulation punctures that might be discovered after special nondestructive testing of apparatus
will require repair or replacement.

The optimum method of avoiding insulation failure is having balanced, or coordinated, pro-
tection. An acceptable system of insulation protection will be influenced by a number of fac-
tors. Of prime importance is a knowledge of the insulation system withstand capability and
endurance qualities. These properties are indicated by insulation-type designations and speci-
fied high-potential and surge-voltage test withstand capabilities. Another facet of the problem
relates to the identification of likely sources of overvoltage exposure and the character, mag-
nitude, duration, and repetition rate that are likely to be impressed on the apparatus and cir-
cuits. The appropriate application of surge-protective devices will lessen the magnitude and
duration of surges as seen by the protected equipment, and is the most effective tool for
achieving the desired insulation security. A working understanding of the behavior pattern of
electric surge voltage propagation along electrical conductors is necessary to achieve the
optimum solution. The problem is complicated by the fact that insulation failure results not
only because of impressed overvoltages, but also because of the aggregate sum total duration
of such overvoltages. No simple devices are available that can correctly integrate the cumula-
tive effects of sequentially applied excessive overvoltage. The time factor must be estimated
and then factored into the design and application of the protection system.

As stated, lightning is a major source of transient overvoltage. Some industrial operations use
open-wire overhead lines that are subject to direct exposure to lightning, allowing lightning
surges to be propagated into the industrial distribution system. However, many industrial
complexes have cable entrances with surge-arrester protection installed at the overhead-to-
underground junction. Although the surge arresters protect the cable entrance, they will not
necessarily protect the substation equipment from incoming surges; additional arresters may
have to be installed at the cable open-end point or last transformer.

Direct lightning strokes are rare to overhead outdoor plant wiring because of the shielding
effect of adjacent structures. However, direct strokes to objects 25-50 ft away can induce sub-
stantial transient overvoltages into the overhead line. Surge arresters should be installed at the
end of an overhead line that connects to the building wiring to minimize the effects of such
induced transients. Another source of sudden overvoltage can be impressed on system con-
ductors when they come into contact with conductors from a higher voltage system.

The National Electrical Safety Code (NESC) (Accredited Standards Committee C2-1993), 1
Rule 222C2, recommends that open conductors of different voltages installed on the same

'information on references can be found in 6.8.

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support must have the highest voltage on top and the lowest voltage below. However, when a
higher voltage conductor breaks for any reason, such as an automobile striking the supporting
pole or a tree limb falling across the line, the higher voltage conductor may fall across the
lower voltage conductor, impressing the higher voltage on the lower voltage circuit. In these
cases, the arresters on the lower voltage line are likely to function and, should the impressed
voltage exceed their temporary overvoltage capability, fail to ground causing a short on the
line. To avoid extensive damage to line and equipment, the fault-current protective equipment
at both line voltages should de-energize the lines as soon as possible.

Steep wave-front transient overvoltages are also generated in plant wiring by switching
actions that change the circuit operation from one steady-state condition to another. Switch-
ing devices that tend to chop the normal ac wave, such as thyristors, vacuum switches, cur-
rent-limiting fuses, and two- or three-cycle circuit breakers, force the current to zero, which
accelerates the collapse of the magnetic field around the conductor, generating a transient
overvoltage. The initial overvoltage spike resulting from the interrupting action of a current-
limiting fuse is depicted in figure 6-2. Restriking current interruption of certain circuit config-
urations by the circuit switching device can also cause high-frequency transient overvoltages.

Figure 6-2— Oscillogram showing typical short-circuit current-limiting
action of fuse to produce transient overvoltage

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Figure 6-3 represents the switching of a shunt capacitor involving restriking during interrup-
tion of the capacitive current. Prior to the initial interruption, £ cap remained solidly refer-
enced to E a . At a capacitor current zero, an initial interruption of current is assumed to occur,
at which time E ca p continues at fixed potential while E A proceeds to reverse according to nor-
mal system operation at fundamental frequency. During the first half-cycle, Ea completely
reverses its potential, which would cause twice the normal line-to-neutral crest voltage to
appear across the open switching contact. Should the switch restrike, it suddenly changes
from an insulator to a conductor. Since the capacitor voltage cannot change instantaneously
(a fundamental property of capacitance), the required transition snaps the “A” phase conduc-
tor to the capacitor voltage. This is a steep-front snap transition. The line and capacitor
together begin a transition oscillation toward where line “A” will eventually be at normal
potential. A corresponding transitory capacitor restrike current is involved in this process that
crosses and recrosses zero. At one of these zero crossings, conditions may be such as to per-
mit another interruption, perhaps with /s’ cap at a greater potential than at the first interruption
as illustrated. This would increase the possible step-voltage transition at the next restrike.
This subject is covered in additional detail in Chapter 8, subclause 8.12.2.

A
B ■
C ■

^cap

= ^ SWITCHED

_ _L POWER-FACTOR
- -p CAPACITOR

(a) Circuit arrangement

SWITCH

OPENING

(b) Transient overvoltage character due to switch restrike during interruption

Figure 6-3— Equivalent circuit and transient response
for capacitor switching restrike phenomena

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In this manner, a 4160 V system may develop a steep-front step- voltage of 2 • J2 ■ 4160 /J3
= 6800 V on the first restrike with greater values possible on subsequent restrikes. Had the
capacitor bank been ungrounded, as it usually is in most industrial systems, there would be
opportunity for more than twice the line-to-neutral crest voltage to appear across the first pole
to clear. In this example, only two restrikes occur. Additional restrikes would cause an even
more dramatic overvoltage condition.

A short circuit (that is, insulation breakdown) is a switching action that creates a bypass
around part of a circuit. The heat generated by the heavy flow of current across the short
circuit may melt or even vaporize the conductor. As it does, it creates a gap with an arc.
Heated air rising from the arc creates a draft causing the arc resistance to fluctuate rapidly,
which produces transient overvoltages. An insulation failure results in an arc through the
failure path with similar results. Overvoltages also can be generated as the nonlinear induc-
tance of an iron-core transformer and a capacitor in the same circuit may go into oscillation
and produce a condition of ferroresonance. Other sources of overvoltages are described in
[B24] 2 and [B25],

Transient overvoltages are propagated along the electric power conductors to create insula-
tion stress far removed from the origin of the voltage surge. Furthermore, the voltage stress
imposed on insulation far removed from the point of surge origin may exceed that appearing
at the source point.

6.2 Traveling-wave behavior

6.2.1 Surge-voltage propagation

Electric power circuits transmit undesired surge voltages equally as well as power frequency
voltages and can do so efficiently, even for frequencies into the megahertz range. When cir-
cuit geometry is short compared to wavelength, lumped circuit constants (L, R, C ) often suf-
fice for the particular analysis at hand. The usual concepts of line impedance, expressed as
resistance and reactance in ohms, used in power-frequency computations do not, however,
apply for the solution of short-time transitory voltages, such as lightning-produced waves
traveling on typical power lines, cables, and other apparatus. When wavelengths (or wave
fronts) are short compared to the lengths of circuitry involved, then it may be necessary to use
a distributed-constant representation.

Figure 6-4 illustrates a distributed-constant electric overhead line, or a solid-insulated cable.
Such a line can be viewed as consisting of a continued succession of small incremental series
inductances with evenly distributed increments of shunt capacitance. When the switch SW is
closed, the voltage E becomes connected to the line terminal. The first increment of capaci-
tance is charged to a voltage E. Current begins to flow through the first increment of L to the
next increment of shunt capacitance. The appearance of voltage along the line is always being

2 The numbers in brackets preceded by the letter B correspond to those of the bibliography in 6.9.

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impeded by the next incremental element of inductance. The voltage wave takes time to travel
down the line.

SW CABLE CONDUCTOR

L = INDUCTANCE (HENRIES/FOOT)
C = CAPACITANCE (FARADS/FOOT)

(b) Equivalent

Figure 6-4— Distributed-constant transmission circuit

The electrical behavior of a distributed-constant transmission line can, for practical surge-
voltage problems, be expressed in terms of the series inductance per unit length L and the
shunt capacitance per identical unit of length C. Consider L in henries and C in farads.

Each elementary inductance has a surge voltage impressed upon it by an assumed traveling
wave. The associated electromagnetic energy ( l h LI 2 ) and electrostatic energy Qh CE 2 ) are
expressed in joules (wattseconds) when units are as defined in figure 6-4. It is a profound
property of traveling waves that the two forms of energy are of equal magnitudes and a surge
impedance Z 0 , which is equal to the voltage/current ratio.

z 0 = eh = Juc

as depicted in figure 6-5. The equivalent distributed-constant relationships exist in apparatus
(transformers, rotating machines, etc.) as well, but are somewhat more complex to analyze
and visualize.

1/%/Tc

z 0 =

sfUc

Figure 6-5— Surge-voltage wave in transit along a line of surge impedance Z 0

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With the prescribed units, the quantity Z 0 has the dimensions of ohms and relates with E
expressed in volts and I in amperes. The quantity is called the surge impedance and assigned
the reference symbol Z 0 . This symbol has no relation to the zero-sequence impedance, which
uses the same symbol.

The applied voltage E and the surge current I are in phase. The current flow duplicates the
wave shape of the impressed voltage and is in phase with it. At this point it appears exactly as
a resistor of ohmic value jLlC , but the behavior differs from that of a resistor. In a true
resistor the 1 2 R line loss energy is converted to heat. In the distributed-constant line the elec-
tric energy is stored in the inductance and capacitance as the LI 2 12 and CE 2 12 of an electric
surge existing on a finite length of the transmission line.

The transit of the surge along the line is propagated at a rate controlled by the quantity
LC. The propagation velocity is expressed as 1/ JTJC . An increased value of the LC product
slows down the transit rate. With the units chosen, the propagation velocity will be in feet per
second. Had L and C been expressed in henries/meter and farads/meter, respectively, the
propagation velocity would have the units of meters per second.

Ignoring the influence of the ground circuit impedance and various second-order effects on an
open-wire line with air dielectric, the propagation velocity is approximately that of the speed
of light, 1000 ft/ // s (304.8 m/pis) or 1 ft/ns (30.48 cm/ns). A solid-insulation cable will display
a propagation velocity about half that of the open-wire line.

Typical values of Z 0 are

200-400 Q for overhead lines
20-50 Q for solid dielectric cables

6.2.2 Surge-voltage reflection

In lines of infinite length, the surge of energy would continue to travel forever, never again to
be observed at the point of origin. Since practical circuits have a finite length, problems
develop as the surge reaches the end of the line.

All types of traveling waves (such as sound, light, current, or voltage) exhibit marked
changes when the travel medium is changed. This is due to a new traveling “reflected” wave
that is created when the original traveling wave impinges upon the change of travel medium.
The reflected wave travels in each direction from this point of origin and is superimposed on
the original wave (called the incident wave), adding to or subtracting from it.

Referring to figure 6-6, if at any instant E is the voltage of the incident wave at the junction,
then (E)(Z 2 - Zj)/(Z 2 + Zj) is the voltage of the reflected wave at the junction where Zj is the
surge impedance of the first conductor (over which the surge arrived) and Z 2 is the surge
impedance of the second conductor. The voltage of the refracted wave at the junction is the
sum of the voltages of the incident and reflected waves; that is, it equals

(£)(2Z 2 )/(Z 2 + Z 1 )

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TRAVELING WAVE

NET WAVE

COMPONENTS

MAGNITUDE

INCIDENT |

POSITIVE

NEGATIVE '

, v i z z' V

to) WAVE TRAVELING IN

z, - z 2

MEDIUM OF NO

z.'j z 2 "

CHANGE OF SURGE

IMPEDANCE - THEREFORE NO REFLECTED WAVE IS
PRODUCED AT JUNCTION BETWEEN Z\ AND Z 2

(b) A CASE OF Zz GREATER THAN Z|. AS Z 2 BECOMES VERY
LARGE COMPARED TO Z|,THE REFLECTED WAVE MAGNITUDE
APPROACHES (AS A LIMIT) THAT OF THE INCIDENT WAVE.

i *

INCIDENT I I

z 2 = ° f

1 1 2

REFLECTED WAVES

(c) LIMITING CASE Zz LESS THAN Z| WHERE Zz *0. THE NET
WAVE MAGNITUDE IN Z 2 (OR REFRACTED WAVE) IS ZERO
SINCE THE INCIDENT WAVE AND REFLECTED WAVE
COMPONENTS ARE EQUAL IN MAGNITUDE ANO OPPOSITE IN
POLARITY IN THE Z 2 REGION.

Source: [B21]

NOTE— The total wave magnitude prevailing is equal to the algebraic sum of the incident and
reflected waves. This is the refracted wave at the junction of the surge impedances and in the Z 2
region.

Figure 6-6— Relative wave magnitudes (for given instant of time) along travel
medium for given changes of surge impedance

Reflected and refracted current waves accompany the corresponding voltage waves, the con-
stant of proportionality between them being the surge impedance Zj or Z 2 of the conductor
the wave is traveling on. A reversal of direction of a voltage wave, without change in polarity,
reverses the direction of flow of current.

As indicated by the equations, if Z 2 is greater than Zj, a voltage wave reflects positively at the
junction, and the voltage at the junction (equal to the voltage of the refracted wave) is greater

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than the voltage of the incident wave. In the limiting case of Z 2 infinite (i.e., line open), the
voltage at the junction is double the voltage of the incident wave. On the other hand, if Z 9 is
less than Zj, the wave reflects negatively and the refracted wave is less than the incident
wave. For the limiting case of Z 2 equal to zero (i.e., line short-circuited to ground), the volt-
age at the junction is equal to zero. The current-to-ground in this case will equal twice the
current of the incident wave.

The equivalent circuit, shown in figure 6-7, allows evaluation of the effect of continuing
along a line of different surge impedance that terminates at an open circuit, at a short circuit,
or with a network of lumped constants. An electric surge E traveling along a transmission line
of surge impedance Z 0 toward a junction J can be replaced by the equivalent circuit shown,
that is, a driving voltage of twice the actual traveling-wave surge voltage magnitude in series
with a resistor of ohmic value Z 0 .

Figure 6-7— Equivalent circuit representing
the arrival of surge at junction J

If at junction J every circuit that exists in the real system, whether a lumped impedance or
distributed-constant line, is connected line to ground, the resulting network correctly satisfies
the voltage-current relationships that will prevail at junction J. Every distributed-constant line
connected to junction J is represented by a line-to-ground-connected resistor of ohmic value
Z 0 for each respective line.

An examination of some familiar line-termination cases will aid in developing a conviction
that the equivalent circuit is indeed a valid one.

a) An open-ended line at junction J [figure 6-8(a)]. The equivalent circuit yields the
following, which we know to be correct:

Junction J voltage = 2 E
Line terminal current = 0

b) A short-circuited line at junction J [figure 6-8(b)]. Therefore, the equivalent circuit
yields the following familiar relationships:

Junction J voltage = 0
Line terminal current = IEIZq

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c) A line joining another line of equal surge impedance at junction J [figure 6-8(c)].
Again, the equivalent circuit correctly yields the following:

Junction J voltage = 2E(Z 0 )/2Z 0
Line terminal current = 2E!2Z {)

J7© -1

JT © -1

(a) Open circuit
at junction J

(b) Grounded circuit
at junction J

J - © - 1

Figure 6-8— Equivalent circuits representing
a line terminated in different ways

The construction of an equivalent circuit for more complex combinations is accomplished
using the techniques described. The simplest equivalent circuit used to accommodate distrib-
uted-constant lines is valid only until a returning reflected wave arrives at the junction under
study. In many cases the entire critical voltage excursion at the bus under study will have
passed before the first reflected wave returns.

To account for the effect of a returning reflected voltage wave, the correct equivalent circuit
for surge arrival of that reflected wave at any bus must be created as if it were an independent
surge voltage initially approaching the bus. The computed voltage that this reflected wave
contributes to the bus is then added with proper polarity to that still being contributed at the
bus by the initial surge. When more than a few wave reflections must be accepted, lattice dia-
gram techniques should be used to ensure correct results ([B 12], Chapter 9, p. 215).

The energy of a traveling wave can be dissipated completely if the traveling wave is directed
to a junction whose equivalent circuit displays a real resistance termination of ohmic value
equal to the Z 0 value of the transmission line. The wave energy is disposed of as heat in the
terminating resistor. Although such terminating devices are seldom applied, they are some-
times called transient snubbers.

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6.2.3 Amplification phenomena

A surge-voltage wave traveling along a distributed- constant line, upon encountering a junc-
tion having a higher surge impedance Z 0 , will increase in voltage to as much as double if the
junction is terminated in an open circuit. A surge arrester installed a finite distance ahead of
such a junction (figure 6-9) could result in a voltage at the junction well above the voltage at
the arrester. The junction voltage rise will depend on the following:

a) The steepness of the surge voltage wave

b) The propagation velocity along the line

c) The distance of the line extension AD

d) The magnitude of surge impedance connected to the terminal junction.

Z<5

-A D-

SURGE ARRESTER

Figure 6-9— Transmission line extended beyond a surge-voltage arrester

The rise in terminal voltage will be aggravated by the following:

a) a steeper front wave

b) slower line propagation velocity

c) greater AD

d) greater magnitude of terminating surge impedance

As long as no other voltage is induced onto the line, the terminal voltage will not exceed
twice the traveling-wave value with any possible value of parameters.

Many application charts are available that display the maximum AD for specific application
conditions. With voltage wave fronts no steeper than 0.5 pis, a separation spacing AD of 25 ft
(7.62 m) is generally allowable. The protection system design should locate the protective
device as close to the terminals of the critical protected apparatus as is reasonable. Surge-
voltage waves may have steeper fronts than the standard reference wave (IEEE Std C62.22-
1991, Appendix C).

A traveling surge voltage, encountering in succession junctions with higher surge impedance,
may have its voltage magnitude elevated to a value in excess of twice the magnitude of the
initial voltage (figure 6-10). Assume the surge impedance of line sections 1 through 4 to be
10 Q, 20 Q, 40 Q, and 70 Q, respectively. Next, assume each line section to be long enough
to contain the complete wave front, distributed along its length. At the junction between

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sections 1 and 2, the refracted wave, which continues, will have a magnitude of 1.33 E. This
wave, encountering the junction between sections 2 and 3, would create a refracted wave of
1.78£. In like fashion, this voltage wave, in turn, encountering the junction of sections 3 and
4, would be increased to 2.21E. This voltage wave, upon reaching the open-end terminal at
section 4, would be doubled to 4.54E.

Zo(l) Z<)12) Zo(3) z 0 ( 4 )

1 1 , •

Figure 6-10— Voltage amplification by a series chain of line sections
of progressively higher surge impedance

Typically, the change in surge impedance might result from a different cable construction,
which may be additionally modified by a different number of cables run in multiple. The
example might well have been represented by four 500 kcmil conductors in parallel in section
1, two in parallel in section 2, one alone in section 3, and a section of bus duct in section 4.
The presence of an open-wire line (400 Q Z 0 ) extension from a cable feeder (40 Q Z 0 ) could,
at an open-end terminal, develop a voltage of 3.64 times the surge voltage traveling in the
cable.

In most instances, a surge voltage approaching a junction bus will encounter a surge imped-
ance of lower value, resulting in a step down rather than a step up in voltage magnitude.
Where step-up conditions exist, supplementary protective devices may be required.

6.3 Insulation voltage withstand characteristics

6.3.1 Introduction

Insulation standards have been developed that recognize the need for electrical equipment to
withstand a limited amount of temporary excess voltage stress over and beyond the normal
operating voltage. The ability of equipment insulation systems to survive these stresses (with-
out unreasonable loss of life expectancy) is verified by overvoltage tests applied to electrical
products at the completion of manufacture. A number of different tests have been developed
and standardized for use in rating equipment. The physical structure of insulation systems
determines the overvoltage withstand properties for electrical equipment. Some of the impor-
tant physical considerations affecting the dielectric strength of insulation systems are given in
6.3.3.

6.3.2 Insulation tests and ratings

The most common standard factory tests are the 1 min, power-frequency applied (high poten-
tial) test and the 1.2/50 full-wave voltage impulse test. For low-voltage circuits of less than

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1000 V additional wave shapes are prescribed in IEEE Std C62.41-1991. Impulse/surge
wave-shape terminology is illustrated in figure 6-11. The 1.2/50 designation means that a
voltage impulse increases from virtual zero volts to its crest value in 1.2 pis (7 1 in figure 6-1 1)
and declines to one-half crest value in 50 pi s (f 2 in figure 6-11). The “pis” or “microsecond”
notation is not included in the wave-shape designation. For practical reasons, the virtual zero
time point on the voltage wave is established by a line drawn through the 30% and 90%
points on the wave front (also illustrated in figure 6-11). The wave shape defined by this des-
ignation is indicated as the full-wave test in figure 6-12. Electrical power and distribution
apparatus assigned a given insulation class should be capable of withstanding, without flash-
over or apparent damage, a 1.2/50 full-wave impulse test of specified crest kV. This specified
crest voltage is the basic impulse insulation level (B1L) of the equipment. Typical values of
test voltages in use today are shown in tables 6-1, 6-2, 6-3, and 6-4.

VOLTAGE WAVE t| X
CURRENT WAVE t 3 X t 4

Source: [B6] .

Figure 6-11 —Terms used to describe voltage and current waves

Transformer insulation systems are generally required to be capable of withstanding other
overvoltage tests besides the 60 Hz hi-pot and full-wave tests. Voltages for two of these tests,
chopped-wave withstand and switching surge withstand, are indicated in table 6-1. For the
chopped-wave test, a 1.2/50 wave with a crest voltage 10% or 15% higher than the full-wave
(BIL) test is chopped by a suitable gap after the specified minimum time to flashover (table
6-1). The resulting wave shape, shown in figure 6-12, has a steep negative gradient that estab-
lishes certain withstand capabilities such as associated with sparkover of gap-type arresters or
bushing flashover. The chopped-wave test stresses the turn-to-turn insulation more than the
line-to-ground insulation, which is checked primarily by the full-wave test. The switching

323

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CHAPTER 6

-i ^
3 <

O L
< (

§1

W L
< {

Figure 6-12— Standard impulse test waves

Table 6-1 —Impulse test levels for liquid-immersed transformers

Insulation

class

and

nominal

bushing

rating

Windings

Bushing withstand voltages

Hi-pot

tests

Chopped wave

BIL full

wave

(1.2/50)

Switch-
ing surge
level

60-cycle

1 min
dry

60-cycle
10 s
wet

BIL
impulse
full wave
(1.2/50)

Minimum
time to flashover

(rms)

(crest)

\iS

(crest)

(rms)

(crest)

1.2

54 (36)

1.5(1)

45 (30)

15 (10)

13 (6)

45 (30)

2.5

69 (54)

1.5 (1.25)

60 (45)

21 (15)

20(13)

60 (45)

5.0

88 (69)

1.6 (1.5)

75 (60)

27 (21)

24 (20)

75 (60)

8.7

110(88)

1.8 (1.6)

95 (75)

35 (27)

30 (24)

95 (75)

15.0

130(110)

2.0 (1.8)

110(95)

50 (35)

45 (30)

110(95)

25.0

175

3.0

150

100

70 (60)

150

34.5

230

3.0

200

140

200

46.0

290

3.0

250

190

120

250

69.0

140

400

3.0

350

280

175

350

92.0

185

520

3.0

450

375

225

190

450

115.0

230

630

3.0

550

460

280

230

550

138.0

275

750

3.0

650

540

335

275

650

161.0

325

865

3.0

750

620

385

315

750

NOTE — Values in parentheses are for distribution transformers, instrument transformers, constant-
current transformers, step- and induction- voltage regulators, and cable potheads for distribution cables.
The switching surge levels shown are applicable only to power transformers (not distribution trans-
formers). Test voltages are defined in IEEE Std C57. 12.00-1980.

324

SURGE VOLTAGE PROTECTION

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Table 6-2— Basic impulse insulation levels (BILs) of power circuit breakers,
switchgear assemblies, and metal-enclosed buses

Voltage

rating

(kV)

BIL

(kv)

Voltage

rating

(kV)

BIL

(kV)

Voltage

rating

(kV)

BIL

(kV)

2.4

150

115

550

4.16

34.5

200

138

650

7.2

75*

250

161

750

13.8

350

230

900

14.4

110

450

345

1300

*95 for metal-clad switchgear with power circuit breakers

Table 6-3— Impulse test levels for dry-type transformers

Nominal winding voltage (volts)

High-potential test

Standard BIL (1.2/50)

Delta or

ungrounded wye

Grounded

wye

kV (rms)

kV (crest)

120-1200

1200Y/693

2520

4360Y/2520

4160-7200

8720Y/5040

8320

12 000-13 800

13 800Y/7970

18 000

22 860Y/13 200

23 000

110

24 940Y/14 400

110

27 600

125

34 500Y/19 920

125

34 500

150

NOTE— Data from IEEE Std C57. 12.01-1979. Nominal voltages shown are exactly as tabulated in
IEEE Std C57. 12.01-1979 and are not, in ail cases, in accordance with the classifications commonly
encountered on industrial and commercial systems.

325

IEEE

Std 141-1993

CHAPTER 6

Table 6-4— Rotating machine high-potential test
and winding impulse voltages, phase-to-ground

Rated motor voltage (volts)

460

2300

4000

4600

6600

13 200

60 Hz, 1 min high-potential
test voltage

Crest value (kilovolts)

Per unit of normal crest

2.71

7.21

7.92

4.22

12.73

3.90

14.43

3.84

20.10

3.73

38.80

3.60

Impulse strength*

Crest value (kilovolts)

Per unit of normal crest

3.39

9.01

9.90

5.27

15.91

4.87

18.00

4.80

25.10

4.66

48.50

4.50

NOTE— Data from ANSI C50. 10-1990 and ANSI C50.13-1989 for synchronous motors, NEMA
MG 1-1993 for induction motors, and [B12],

*The 1.2/50 full wave test does not apply to rotating machines. See figure 6-13 and related discussion.

surge level test certifies the capability of an insulation system to withstand the transient over-
voltages produced by such conditions as arcing ground faults or the switching of capacitor
banks, lines, or transformers.

The impulse voltage waves used in switching surge level tests are based on the characteristics
of these voltage disturbances, which may be generally described as much slower than those
caused by lightning. Since some switching phenomena may produce very fast front waves, to
characterize all switching surges as slow can be misleading. IEEE Std C62. 11-1987 has
adopted slow-front as being preferable to the designation switching surge. The test standard
requires that the gapless surge arresters be tested with a wave shape having a wave front time
of 45-60 pis. Typical transformer switching surge test crest voltages, which are 83% of the
BIL for transformers of 45 kV BIL and higher, are listed in table 6-1. One other test, which is
sometimes specified as another check on the strength of turn-to-turn insulation, is the front-
of-wave test. The front-of-wave test is similar to the chopped-wave test except the voltage is
higher, and the impulse is chopped on the rising front of the wave before the normal crest.

Tables 6-1, 6-2, and 6-3 provide a general picture of the standardized impulse capabilities of
transformers and switchgear. These voltage withstand characteristics are useful for coordinat-
ing the equipment capabilities with the protective characteristics of surge arresters, an analyt-
ical procedure known as insulation coordination. The subject of insulation coordination is
discussed in 6.6.2. Comparison of tables 6-1 and 6-3 shows that the BILs of standard dry-
type transformers are relatively low (higher BIL dry-type transformers can be acquired with
additional cost). Also, the insulation strength of standard dry-type transformers does not
increase appreciably as the duration of the applied impulse decreases.

Open-wire lines vary somewhat in their impulse withstand capacity depending upon such fac-
tors as design construction, maintenance, and weather, but are generally considered well

326

SURGE VOLTAGE PROTECTION

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Std 141-1993

above associated transformers in this respect. An open-wire 13.8 kV distribution circuit, for
example, is typically considered to have a 150-500 kV BIL. While cables do not have
assigned BILs, they too have impulse capability significantly higher than associated liquid-
immersed transformers.

Rotating machines, like standard dry-type transformers, have relatively low impulse strength
and have no established, standardized BILs. Rotating machines do, however, have standard
high-potential test voltage values (shown in table 6-4), which have become important in the
application of surge protection. An IEEE Working Group report [B 19] contains a proposed
voltage-time boundary (figure 6-13) where the maximum impulse voltage is 1.25 times the
crest value of the standard high-potential test voltages. These values are also shown in
table 6-4.

For V L = machine voltage rating line-to-line rms kV:

V, = \fl7z V L = 1 PER UNIT CREST LINE-TO-GROUND
V 2 = 2 V,

V 3 = 1 .25 \[2 (2 V L + 1 ), kV CREST VALUE

Figure 6-13 — Machine impulse voltage withstand envelope

6.3.3 Physical properties affecting insulation strength

For each item of electrical apparatus to be protected, the security of major insulation (line-to-
ground) and, where applicable, turn insulation (tum-to-turn) should be considered separately.

Circumstances will exist in which one of these organic insulation systems may be over-
stressed, while the other one is not subjected to any abnormal stress at all. The security of
each must be independently examined and protected as necessary.

327

IEEE

Std 141-1993

CHAPTER 6

One of the confusing aspects of an organic insulation system capability and its protection is
the progressive accumulation of deterioration within the dielectric that results from the com-
plete history of voltage stress exposure. An item of equipment subjected to a 60 Hz high-
potential test may withstand the voltage application for 50 seconds and then break down. The
device failed the test. It may have withstood the voltage application for the entire specified/
required 60-second period and passed the test, but it might have failed had the test voltage
been continued for another 10 cycles.

With certain types of electric apparatus having a combination of liquid and solid insulation
systems, the cumulative stress failure mechanism only occurs within a narrow band of stress
voltages just below the breakdown voltage. Exposure to a lesser overvoltage may initially
cause an incomplete failure of the solid insulation, but the subsequent penetration by the liq-
uid material will partially repair the deteriorating region.

In all cases, a large fraction of the insulation system’s capability to withstand applied voltage
can be destroyed simply by the process of testing it. For this reason overtesting with dynamic
ac voltage should be avoided. Direct-current testing is preferred. The design of the electric
system, including the use of surge suppression devices (to assure adequate insulation secu-
rity), should correctly interpret the effect of the inverse relationship between imposed voltage
magnitude and the allowable duration. A 30% increase in the applied ac voltage magnitude
for most equipment will result in a tenfold reduction in insulation life. The high-magnitude
surges require careful attention because of the very rapid loss of life. The system design engi-
neer must, largely by judgment, set the margin of safety between the design controls of
allowed overvoltage exposure and the certified withstand capability of the insulation system,
based on ones knowledge of the probable character and repetition rate of troublesome surge
voltage transients.

The problems relating to the achievement of insulation security for turn-to-turn insulation in
multi-turn coils are many and complex. The normal 60 Hz voltage developed in a single turn
will range from perhaps a small fraction of 1 V in a contactor magnet coil to 20 V in a
medium-sized induction motor to several hundred volts in a large transformer. If it were nec-
essary to only insulate for this normal operating voltage developed in a single turn, the prob-
lem would be simple. However, the voltage stress that appears across a single turn-to-turn
insulation element when high rate-of-rise voltage surges occur may be much greater than the
single-turn operating voltage.

This aggravated voltage stress is most pronounced at turn insulation adjacent to the coil ter-
minals and is intensified by the increased shunt capacitance between winding sections and
ground, such as exists inherently in motor windings as a result of each coil in the construction
being surrounded by grounded stator core iron.

The controlling parameters (figure 6-14) are the elemental values of coil series inductance
A L, the elemental values of capacitance C$ shunting the above elemental coil segments, and
the elemental capacitance to ground Cq.

Under normal 60 Hz excitation, the voltage distribution is controlled almost entirely by the
series-connected chain of elemental coil inductances, creating equal division of the

328

SURGE VOLTAGE PROTECTION

IEEE
Std 141-1993

Figure 6-14— LC network in a multi-turn winding

impressed voltage across all turns. A steep-front voltage applied to the line terminal creates
an entirely different pattern of distributed voltage. Consider the incoming voltage wave to be
a step voltage of infinite rate of rise. If only the turn shunting capacitance C s were present,
the incoming transient overvoltage would be uniformly distributed. The distributed capaci-
tive coupling to ground C G is responsible for the non-uniform voltage distribution. Note that
each elemental capacitance to ground C G tends directly to hold the coil turns with which it is
coupled at ground potential. If C s were zero, a step voltage at the terminal would create full
voltage at the terminal end of the first coil. The inner end of the first coil, and all coils deeper
in the winding, would remain at ground potential as controlled by C G . Only as current flow
begins through the first coil inductance A L could any voltage appear across any C G (except
the one unit at the terminal). Thus the initial voltage distribution would display the full surge
voltage across the terminal coil with zero voltage across all coils deeper in the winding.

Following the initial steep-front voltage application, current flow will build up in the A L,
which will redistribute the voltage more uniformly. In the process, the internal L-C oscilla-
tions will create a voltage drop across some inner coil (or coils) substantially greater than the
uniform-distribution value, but seldom as great as the initial voltage stress across the terminal
coil.

In an actual motor winding, a very high percentage (upwards of 90%) of an applied surge
voltage with a 0.1 pis front can appear across the terminal coil. Unfortunately, the internal
electric network by which most apparatus can be represented is not commonly found in

329

IEEE

Std 141-1993

CHAPTER 6

equipment specifications or industry standards. In the case of rotating machines, a guide to
achieve turn-insulation security is presented in 6. 7. 3. 9.

6.4 Arrester characteristics and ratings

6.4.1 Introduction

Historically, the evolution of surge arrester material technology has produced various arrester
designs culminating in the so-called valve-type arrester, which has been used practically
exclusively on power system protection for several decades. The active element (called valve
element) in these arresters is a nonlinear resistor that exhibits relatively high resistance
(megohms) at system operating voltages, and a much lower resistance (ohms) at fast rate-
of-rise surge voltages. In all applications, arresters are exposed to continuous system funda-
mental frequency voltages. Arresters must exhibit high resistance at these voltages. Low
resistance at surge voltage is desirable for the arresters to achieve satisfactory surge protec-
tion. Obviously, the greater the nonlinearity of the valve element, the greater the protective
efficiency.

For several decades valve elements were composed of silicon carbide (SIC), a dense sintered
ceramic-like material. Since silicon carbide valve elements of sufficiently low resistance to
achieve effective surge protection were too low in resistance to be exposed to the continuous
system operating voltage, it was necessary to isolate them from the system operating voltage
with series gaps. Internally designed gaps were used in series with the silicon carbide valve
elements to produce the optimum surge-protective characteristics for this technology. These
surge arresters are now commonly called “gapped silicon carbide” arresters, and many such
surge arresters are still in service on power systems today.

In the mid 1970s, arresters with metal-oxide valve elements were introduced. These metal-
oxide arresters have valve elements (also of sintered ceramic-like material) of a much greater
nonlinearity than silicon carbide arresters, and series gaps are no longer required. Some
metal-oxide designs employ the use of a modified gap design that retains the essential protec-
tive advantages of gapless construction. As such, the metal-oxide designs offer improved pro-
tective characteristics and improvement in various other characteristics, as compared to the
silicon-carbide designs. As a result, the metal-oxide arrester has replaced the gapped silicon-
carbide arrester, in virtually all new applications.

In the mid-1980s polymer housings appeared and began to replace porcelain housings on
metal-oxide surge arresters offered by some manufacturers. The polymer housings are made of
either EPDM or silicone rubber. First the distribution arrester housings were made with poly-
mer, and later expanded to the intermediate and some station class ratings. This new housing
material reduces the risk of injuries and/or equipment damage due to surge arrester failures.

Silicon-carbide arresters are not covered in this publication. Some specifics of comparison
between the metal-oxide and silicon carbide arresters are presented in | B49] .

The most authoritative information regarding the testing and application of silicon carbide
arresters can be found in IEEE Std C62. 1-1989 and IEEE Std C62. 2-1987.

330

SURGE VOLTAGE PROTECTION

IEEE
Std 141-1993

IEEE Std C62.1 1-1987 and IEEE Std C62. 22-1991 are two IEEE arrester standards of partic-
ular interest for medium- and high-voltage protection as they relate to metal-oxide technol-
ogy. Much of the information presented here will be extracted from or referenced to these
standards, as they represent the latest source of information.

6.4.2 Metal-oxide arresters

The valve element of the metal oxide arrester is processed in a manner similar to that of the
silicon carbide arrester, by pressing their respective ingredients into discs and sintering at
high temperature into a dense ceramic. The nonlinearity of the metal oxide valve element,
however, is much greater than the silicon carbide valve. For instance if

I = kV*

oc = 10 for silicon carbide
oc = 50 for metal oxide

Figure 6-15 compares the relative degree of nonlinearity of the metal oxide versus silicon car-
bide materials by a normalized log-log plot of volts (per millimeter of disc thickness) versus
amperes (per square centimeter of disc area).

Source: [B49]

Figure 6-15— Typical voltage-ampere characteristics of zinc oxide
and silicon carbide valve-element discs

6.4.3 Basis of arrester rating

Metal-oxide surge arresters have a dual (fundamental-frequency |rms]) voltage rating, a
so-called duty-cycle voltage rating, and a corresponding maximum continuous operating
voltage rating (MCOV).

331

IEEE

Std 141-1993

CHAPTER 6

IEEE Std C62. 11-1987 defines duty-cycle voltage as, “the designated maximum permissible
voltage between its terminals at which an arrester is designed to perform its duty cycle.” The
duty cycle is the duty-cycle test which serves to establish the ability of the arrester to dis-
charge impulse current while energized at duty-cycle voltage and thermally recover at
MCOV. For arresters applied to medium- and high-voltage systems up to 550 kV, the test
involves the application of twenty high-current impulses (5000 or 10 000 A, 8/20 fis). The
interval between impulses is 50-60 seconds. The associated impulse current magnitudes are
the “classifying” current magnitudes by which arrester classes are established (see 6.4.5).

The maximum designated root-mean-square (rms) maximum continuous operating voltage
(MCOV) value is the power-frequency voltage that may be applied continuously between the
terminals of the arrester.

Note that arresters are rated on the basis of the associated applied system power-frequency
voltage and not in relation to their surge-protective characteristics.

6.4.4 Protective characteristics

Metal-oxide arrester protective characteristics are provided in terms of the maximum voltage
associated with discharging a specified magnitude of surge current through them. Three cate-
gories of protective voltage characteristics are established by industry standards (and com-
monly published by arrester manufacturers) which relate to three specific discharge current
wave shapes. They are (1) front-of-wave (FOW) protective level, (2) lightning impulse pro-
tective level (LPL), also referred to as the discharge voltage ( IR ) of the surge arrester, and (3)
switching impulse protective level (SPL).

The front-of-wave (FOW) protective level is defined in IEEE Std C62.1 1-1987 as “the higher
of (1) crest discharge voltage resulting from a current wave through the arrester of lightning
impulse classifying current (defined in 6.4.5) magnitude with a rate-of-rise high enough to
produce arrester crest voltage in 0.5 //s or (2) gap sparkover voltage on similar wave shapes.”
The lightning impulse classifying current ranges between 1.5 kA and 20 kA depending on
arrester class and voltage rating (IEEE Std C62.1 1-1987).

The IR is the voltage that appears across the arrester when a standard 8/20 current wave is
conducted through the arrester. In published information the IR values are associated with a
range of 8/20 current magnitudes. See tables 6-5 and 6-6, which list arrester protective
characteristics.

The SPL is defined in IEEE Std C62.1 1-1987 as “the higher of (1) the discharge voltage with
a current wave through an arrester of switching impulse classifying current magnitude and a
time of actual current crest of 30-2000 pis, or (2) gap sparkover on similar wave shape.” The
switching surge classifying current ranges between 500 A and 2000 A, depending on voltage,
and applies to station class and intermediate class arresters (IEEE Std C62.1 1-1987).

Arrester standard IEEE Std C62. 11-1987 specifies various wave shape tests whereby pro-
tective levels of metal-oxide surge arresters are evaluated. Arrester manufacturers list per-
formance characteristics based on these wave shapes. The two tests most frequently used for
such listings are the front-of-wave and the 8/20 wave discharge test (IR).

332

Table 6-5— Station and intermediate-class (MOV) arrester characteristics

SURGE VOLTAGE PROTECTION

IEEE
Std 141-1993

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334

SURGE VOLTAGE PROTECTION

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Std 141-1993

Tables 6-5 and 6-6 show the maximum discharge voltages associated with various 8/20 dis-
charge currents for arresters rated 2.7-228 kV. Note that very large increases in discharge
current result in relatively small increases in discharge voltage. This exhibits the nonlinear
nature of the metal-oxide valve units.

Virtually all discharge currents in effectively shielded industrial installations will be less than
10 kA, the vast majority being only a small fraction of this magnitude.

6.4.5 Arrester classes

Four classes of valve-type arresters are recognized by industry standards that specify light-
ning impulse “classifying” and switching surge “classifying” current requirements for the
respective classes (IEEE Std C62.1 1-1987). In order of decreasing cost and overall protection
and durability, these classes are as follows:

a) Station class

b) Intermediate class

c) Distribution class— heavy duty
Distribution class— normal duty

d) Secondary

Tables 6-5 and 6-6 list protective characteristics of the metal-oxide arresters. It should be
noted that the values listed in tables 6-5 and 6-6 are representative of several manufacturers.
The nature of the zinc-oxide-based material used in the valve elements of this design is such
that the protective characteristics among the four classes are relatively uniform. There are,
however, distinct differences in design features, sizes, etc., among the high-voltage classes
that enhance particularly the repetitive duty-cycle capability of the station class relative to the
intermediate class, and the intermediate class relative to the distribution class.

6.4.6 Arrester discharge-current withstand capability

To further ensure that arresters have an acceptable capability to discharge lightning currents
and line and cable charged capacitance, an array of discharge-current withstand tests are
specified by standards. Two of the tests relate to high-current, short-duration and to low-cur-
rent, long-duration duties. The high-current, short-duration test consists of two discharges of
a surge current (65 kA crest for station, intermediate, and distribution normal duty class
arresters, 100 kA crest for distribution heavy-duty class arresters, and 10 kA for secondary
arresters) having a (4—6)/ ( 1 0— 15) pis wave shape. These low-current, long-duration tests
require station and intermediate class arresters to display capability to discharge charged
capacitance equivalent to specified transmission line lengths (150-200 mi for station class,
depending upon arrester rating, and 100 mi for intermediate class). Distribution arresters
must exhibit (in a specified series of discharges) the capability of withstanding an approxi-
mate rectangular wave shape of 75 A minimum surge current with a minimum time duration
of 2000 pis for normal duty, and 250 A, 2000 pis for heavy duty. Some arresters have dis-
charge capabilities well in excess of these indicated minimums. Where high discharge cur-
rents are of concern, consult arrester manufacturer data to determine adequacy of arrester
discharge capability.

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The energy absorption capability of surge arresters upon current discharge is limited, for a
single event, by the thermal shock the valve element discs can sustain without puncturing or
cracking. In general, the metal-oxide arrester sudden absorption capability is one to two
orders of magnitude greater than the stored energy in the line used to perform the standard
transmission line discharge test at these voltages (3-230 kV). After an interval of approxi-
mately one minute to permit equalization of temperature throughout the discs, an additional
approximately equal amount of energy absorption is permissible up to the transient thermal
stability limit. This total (thermal stability) limit of energy absorption capability is approxi-
mately three times the energy absorbed in the standard (20 operations) duty-cycle test and is
well above the capability of silicon-carbide arresters — an important consideration for severe -
duty applications, such as for installation near a large, switched capacitor bank.

6.5 Arrester selection

For a given application, the selection of an appropriate arrester involves consideration of
MCOV, protective characteristics (lightning and switching impulse), durability (temporary
overvoltage and switching surge), service conditions, and pressure-relief requirements. Dura-
bility and protective level primarily determine the class of arrester selected: station, interme-
diate, or distribution.

Station arresters are designed for heavy-duty applications. They have the widest range of rat-
ings, the lowest protective characteristics, and the highest durability.

Intermediate arresters are designed for moderate duty and system voltages of 169 kV and
below.

Distribution arresters are used to protect lower voltage transformers and lines where the
system-imposed duty is minimal and there is a need for an economical design.

6.5.1 Maximum continuous operating voltage (MCOV)

For each arrester location, arrester maximum fundamental-frequency operating voltage must
equal or exceed the expected MCOV imposed by the system. Proper application requires that
the system configuration (single-phase, delta, or wye), system grounding, and the arrester
connection (phase-to-ground, phase-to-phase, or phase-to-neutral) be evaluated. In rare cases,
arresters in industrial systems are connected phase-to-ground and, therefore, are exposed to
system phase-ground voltages on a steady-state basis. On the other hand, an arrester con-
nected to an ungrounded or resistance-grounded system will be exposed to phase-to-phase
voltage during intervals when the system is operated with a fault-to-ground on one phase. A
large majority of industrial medium- voltage systems are resistance-grounded.

6.5.2 Temporary overvoltage (TOV) durability

An arrester must be capable of withstanding the maximum anticipated TOV duty. TOV
requirements must take into account both magnitudes and durations of temporary overvolt-

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ages, the combinations of which must be equal to or less than the capability of the arrester as
shown by the TOV capability curves published by the manufacturers.

There are several sources of TOV and operating conditions that can affect arrester operation,
such as the following:

a) Line-to-ground fault, particularly on an ungrounded or resistance-grounded system

b) Loss of neutral ground on a normally grounded system

c) Sudden loss of load or generator overspeed, or both

d) Resonance effects and induction from parallel circuits

The most common source of TOV and the most common basis of TOV determination is the
voltage rise on unfaulted phases during a line-to-ground fault. Line-to-ground faults tend to
shift the system fundamental frequency phasor pattern from its normal position of symmetry
with respect to ground. In the case of ungrounded systems, this shift is virtually complete;
that is, the unfaulted (sound) phase arrester(s) will be subjected to 100% of the line-to-line
operating voltage. However, a solidly grounded system (depending upon degree) provides
considerable restraint in voltage pattern shift and usually permits a considerable reduction in
arrester rating requirement.

IEEE Std C62.22-1991 defines coefficient of grounding as “The ratio expressed as a

percentage, of the highest root-mean-square line-to-ground power-frequency voltage Zs LG on
a solid phase, at a selected location, during a fault to ground affecting one or more phases to
the line-to-line power-frequency voltage £ll which would be obtained, at the selected loca-
tion. with the fault removed.” Appendix B of IEEE Std C62. 22-1991 provides a guide to
facilitate the calculation and determination of coefficients of grounding. As in this standard,
such aids are often presented in terms of symmetrical component parameters, and surge
arrester rating selection practices have evolved to a certain extent around symmetrical com-
ponent resistance and reactance terminology (Rq/X i, X 0 /X l ratios). Further, systems have
been categorized as follows to aid in arrester rating selection:

a) Effectively grounded— coefficient of grounding not exceeding 80% (X 0 /X [ is posi-
tive and less than three, and Rq/X i is positive and less than one)

b) Non-effectively grounded or ungrounded when coefficient of grounding exceeds 80%

The vast majority of medium-voltage (2.4-13.8 kV) industrial power systems employ some
form of resistance grounding. For arrester application purposes, these are non-effectively
grounded systems having coefficients of grounding of 100%. The same is true for the infre-
quently used ungrounded systems.

Some industrial complexes are served by medium-voltage systems that utilize solid system
grounding only at the point of energy supply to the system. These systems exhibit a range of
coefficients of grounding (usually less than 80%), depending upon the system or location in
the system. Therefore, these systems require individual study to ensure the most economical,
secure, arrester rating selection.

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Many high-voltage transmission systems may exhibit coefficients of grounding as low as
70%, and certain multigrounded four-wire distribution systems may be even slightly less.

The coefficient of grounding as a measure of the system grounding effectiveness is very
important when applying arresters. On effectively grounded systems, for example, an arrester
may be momentarily subjected to aTOV voltage of up to 120-140% of normal line-to-ground
voltage during a ground fault involving another system phase. The most likely situation
where this might occur would be for a lightning-produced overvoltage that caused a flashover
(line-to-ground fault) on one phase of the system and a voltage surge of sufficient magnitude
to simultaneously cause arrester protective action on the unfaulted phases. On non-effectively
grounded systems, the TOV applied to the arrester is not only greater in magnitude,
approaching line-to-line voltage as a limit, but is sometimes applied for substantially longer
periods of time as in high-resistance grounding applications.

6.5.3 Switching surge durability

Surge arresters dissipate switching surges by absorbing thermal energy. The amount of
energy is related to the prospective switching magnitude, its wave shape, the system imped-
ance, circuit topology, the arrester voltage-current characteristics, and the number of opera-
tions (single or multiple events). The selected arrester should have an energy capability
greater than the energy associated with the expected switching surges on the system (IEEE
Std C62. 22-1991).

Stored energy in transmission lines, long cable circuits, and large capacitors are the principal
sources of switching surge energy that impacts arresters. Rarely in industrial systems is such
energy sufficient to jeopardize arresters. Transmission lines of 50-100 mi or more at 1 15 kV
and above are necessary to represent a potential jeopardy to arresters. Many industrial plants
have extensive cable installations, but the associated voltage is such that the associated stored
energy is relatively limited. Similarly, the capacitor banks installed within industrial com-
plexes very often have limited capacity. Where extensive cable installations and/or very large
capacitor banks are planned, particularly at 34.5 kV and above, it would be prudent to ensure
that the arrester switching surge capability is not exceeded. Arrester manufacturers’ applica-
tion data and IEEE Std C62.22-1991 may be consulted for guidance. The best determination
of arrester duty is made via analog or digital modeling, where system and arrester details can
be represented accurately. Refer to [B 17], pages 282 and 284.

6.5.4 Selection of arrester voltage rating

The arrester voltage rating should be tentatively selected on the basis of MCOV, TOV, and
switching surge durability. Special attention should be given to the abnormal system operat-
ing voltages as given under 6.5.2.

6.6 Selection of arrester class

The arrester class should be selected on the basis of required level of equipment protection
(protective levels summarized in tables 6-5 and 6-6), and the following:

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a) Available voltage ratings (see tables 6-5 and 6-6)

b) Pressure-relief current limits, which should not be exceeded by the system’s available
short-circuit current and duration at the arrester location

c) Durability characteristics (see tables 6-5 and 6-6) that are adequate for systems
requirements

Arrester failures may entail very low arrester impedance. As such, arrester failure on one
phase will result directly in arrester current that approaches system phase-to-ground fault cur-
rent magnitude. In ungrounded and resistance-grounded systems (as in most industrial
medium-voltage systems) ground fault currents are very limited and range from a few
amperes to perhaps as high as 2000 A. In solidly grounded systems the ground-fault current
may approach or even slightly exceed the three-phase fault current magnitude. A failed
arrester may be required to carry phase-to-phase fault current (0.87 times three-phase fault
current) when it participates in a double phase-to-ground fault, regardless of system ground-
ing. Such currents may produce explosive pressure build-up due to the associated rapid heat-
ing effects and gas generation inside the arrester. IEEE Std C62. 11-1987 requires that
pressure-relief devices be incorporated in all station and intermediate arrester designs to
ensure safe containment of otherwise possible dangerous arrester disintegration during the
passage of system high short-circuit current through them. This standard requires pressure
relief for standard (metal-top) designs up to system short-circuit currents as follows:

Dutv cvcle voltage/class

Symmetrical rms A

Duration (seconds)

3-72 kV station arresters

40 000-65 000

0.2

Above 72 kV station arresters

40 000-65 000

0.1

All voltages intermediate

16 100

0.2

Many arrester manufacturers offer capabilities in excess of the above for station-class and
intermediate-class arresters. Note that short-circuit duties in many industrial systems may
exceed the 16 100 rms A symmetrical required by the standard for intermediate arresters.
Also, pressure-relief capability for the popular porcelain-top arrester designs has not been
standardized, but some manufacturers offer polymer designs with pressure-relief capability
equal to station- and intermediate-class surge arresters, which also have the enclosure space-
saving feature as porcelain-top designs.

Pressure-relief capabilities are not standardized for distribution arresters, but IEEE Std
C62.22-1991 does require that all distribution class arresters for which a fault-current with-
stand rating is claimed shall be tested in accordance with procedures (set forth therein) simi-
lar to those for station and intermediate arresters.

The class of arrester selected may be influenced by the importance of the station or equip-
ment to be protected. For example, station-class arresters should be used in large substations.
Intermediate-class arresters may be used in smaller substations and on sub-transmission lines
and cable terminal poles at 161 kV and below. Distribution-class arresters might be used in
small distribution substations to protect distribution voltage buses.

In the distribution class there are three basic arrester categories recognized by the metal-
oxide arrester application standard, IEEE Std C62.22-1991: normal duty, heavy duty, and

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riser pole. The riser pole arrester, as its name implies, originally was designed for application
at overhead line-cable junctions for the protection of underground cables and equipment and
pad-mounted transformers. As such, these designs must have the lowest practical protective
levels. Some manufacturers’ riser pole designs have protective characteristics comparable to
station class. Where suitable ratings are available, riser pole arresters are good candidates for
rotating machine protection. So-called “elbow” distribution class arresters are available that
facilitate protection at cable-to-equipment junctions.

There is relatively little difference in the protective levels of the normal-duty and heavy-duty
arresters at typical industrial plant discharge voltages. The heavy-duty arrester has substan-
tially higher discharge current capability (high current, short duration; low current, long dura-
tion; and duty cycle classifying current) than the normal-duty arrester. The heavy-duty
arrester is applicable in exposed severe lightning area distribution circuits.

6.6.1 Arrester location

A major factor in locating arresters within a station or substation is the line and equipment
shielding. It is usually feasible to provide shielding for the substation even if the associated
lines are unshielded. Station shielding reduces the probability of high voltages and steep
fronts within the station resulting from high-current lightning strokes. However, it should be
recognized that the majority of strokes will be to the lines, creating surges that travel along
the line and into the station. If the lines are shielded, the surges entering the station are less
severe than those from unshielded lines. Consequently, the magnitude of the protective
arrester currents is lower, resulting in better protective levels (IEEE Std. C62. 22-1991).

6.6.2 Separation effects

The voltage at the protected insulation will usually be higher than at the arrester terminals
due to the Ldi/dt of the connecting leads. This rise in voltage is called the separation effect
(SE).

Separation effects increase with the increasing rate of rise of the incoming surge and with
increasing distances between the arrester and protected equipment. For evaluation of separa-
tion effects due to lightning surges, refer to IEEE Std C62.22-1991, Appendix C. Due to the
relatively slow rates of rise of switching surges, separation effects need not be considered in
applying the fundamental protective ratio formula to switching surge withstand ( basic surge
level [BSL]) (IEEE Std C62.22-1991).

6.7 Application concepts

6.7.1 General considerations

Lightning is considered to be the most severe source of surge voltages and, for that reason,
lightning protection is the main subject of the following discussion. It is to be understood,
however, that many of the protection principles involved, particularly regarding wave magni-

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tude and wave-shape control, apply to situations involving surges of non-lightning origin as
well.

In actual practice, lightning protection is achieved by the processes of interception of light-
ning-produced surges, diverting them to ground, and by altering their associated wave shapes
[B50], Interception relates primarily to the prevention of direct strokes to lines and apparatus
by shielding, which also functions as an energy diversion path to ground. However, an
extremely low percentage of strokes may penetrate overhead line static wire shielding in
addition to induced surges that will occur on the line in presence of lightning in the area.
Also, of course, some lines are not shielded. Therefore, lightning-produced surges do become
impressed on power system components due to imperfect or nonexistent shielding. Strategi-
cally located arresters are applied to divert most of this surge energy around sensitive appara-
tus insulation and thus afford the necessary protection. In the most ideal and simplest
applications, the surge arresters are connected in the closest practical shunt relationships with
the insulation of the apparatus to be protected. Surge capacitors may be applied to alter the
shape of a steep incoming wavefront. The rate of rise of the surge voltage at the capacitor ter-
minals is limited by the charging rate of the capacitor.

While most apparatus in the large majority of applications will tolerate the surge duties per-
mitted by good shielding and proper arrester application, the associated gradients in particu-
lar may be damaging to rotating machines of multi-turn coil construction. This includes
virtually all motors and also generators up to approximately 35^-0 MW at 13.8 kV. A discus-
sion of motor protection in 6. 7. 3. 9. 2 covers this aspect of surge protection and associated
application of surge capacitors.

Internally generated surge sources should be recognized, as well as lightning surges, in order
that the system is properly protected against all sources of hazardous overvoltage. These tran-
sient overvoltages can be produced by current-limiting fuse operation, vacuum and high-
speed circuit breaker operations, thyristor switching, and ferroresonance. A more detailed
description of these phenomena was given in 6. 1 .

6.7.2 Insulation coordination

Insulation coordination is defined in ANSI C92. 1-1982 as “the process of correlating the
insulation strengths of electrical equipment with expected overvoltages and with the charac-
teristics of surge-protective devices.” Fundamentally, insulation coordination involves check-
ing to determine that an adequate margin of protection exists between the insulation
withstand characteristic of the electrical apparatus and the protective characteristic of the
applied surge arrester for any voltage impulse likely to be encountered. This is often demon-
strated graphically, as shown in figure 6-16, where the test- implied transformer insulation
withstand curve is an attempt to simulate the actual withstand curve. It should be recognized
that the technique of simulating the actual withstand curve from the results of the four (at
most) generally available insulation tests discussed in 6.3.2 and graphically shown in figure
6-16 is at best an approximation since different wave shapes are employed. Using such a
curve on the same graph with a surge-arrester-protective characteristic curve that is based on
tests performed using still other wave shapes is, therefore, not a truly accurate representation.
For this reason, the calculation of three standardized protective margins that may be com-

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pared to recommended minimums is preferred over graphical techniques for insulation
coordination.

MAXIMUM
FRONT-OF-WAVi
(FOW)

SPARKOVER

FRONT-OF-WAVE TEST

CHOPPED-WAVE TEST

FULL-WAVE TEST (BIL)
SWITCHING SURGE TEST

DISCHARGE VOLTAGE
FOR 8 X 20 /us CURRENT
WAVE (20 kA CREST)

I L

MAXIMUM SWITCHING SURGE
SPARKOVER (B) OR
DISCHARGE VOLTAGE (C)

0.1

100

1000

TIME (/us)

A— TEST-IMPLIED TRANSFORMER WITHSTAND CURVE
B — GAP-TYPE ARRESTER CHARACTERISTIC
C — METAL OXIDE (GAPLESS) ARRESTER CHARACTERISTIC

Figure 6-16— Insulation coordination based on
test-implied transformer withstand curve

The degree of coordination is measured by th e protective ratio (PR). The fundamental defini-
tion of PR is

PR = insulation withstand level/voltage at protected equipment

Voltage at protected equipment includes separation effect, if significant. If not, it is equal to
arrester protective level.

There are three protective ratios in common use that compare protective levels with corre-
sponding insulation withstands:

PRd = chopped wave withstand/front of wave = CWW/FOW

PR L2 = basic lightning impulse level/lightning protective level = BIL/LPL

PR S = basic surge level/switching protective level = BSL/SPL

The protective margin (PM) in percent is defined as

PM = (PR-1) 100%

PR and PM applications are covered in detail in IEEE Std C62.22-1991.

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6.7.3 Component protection

6.7.3. 1 Outdoor substations

While actual lightning protective practices may necessarily vary from one type of installation
to the next, the most basic categorical division relates to whether the installation is effectively
shielded or non-effectively shielded. It is common practice to provide a safety factor of pro-
tective margin between established impulse capability of apparatus insulation and the protec-
tive level provided by arresters. The generally recommended minimum protective margin,
defined in 6.7.2, that is generally recommended is 20% for impulse coordination (front-of-
wave, full wave) and 15% for switching surge coordination.

It is very important that the lowest practical ground resistance be obtained and that the con-
nections between arrester ground and terminal, and the protected equipment, be as short as
possible. Additionally, ground interconnections between these two points are often employed
to place an arrester in closest practical shunt with insulation to be protected.

6.7.3. 1.1 Effectively shielded substations

Direct lightning strokes to equipment located in substations can cause a considerable amount
of damage. This equipment should be protected from direct strokes. Such protection has been
accomplished by intercepting lightning strokes and diverting them to ground using shield
wires and/or masts.

Two basic approaches have historically been used to design the direct stroke shielding of sub-
stations and switchyards:

a) The empirical method

b) The electrogeometric model

The empirical method involves either the use of fixed angles or the use of empirical curves.
The fixed-angle design method uses the vertical angles between shield wires or masts and the
equipment to be protected to determine the number, position, and height of the shield wire
and masts [B28]. The angles used are determined by the degree of lightning exposure, the
importance of the substation being protected, and the physical area occupied by the substa-
tion. For substations below 345 kV, an angle of 45° or less has been used between shield wire
or mast and the equipment to be protected. Empirical curves have been developed from field
studies of lightning and laboratory model tests. These curves can be used to determine the
number, position, and height of shield wires and masts. The curves were derived for different
configurations of shield wires and masts and for different estimated shielding failure rates
[B28], [B48],

The electrogeometric model is a geometrical representation of a facility which, together with
suitable analytical expressions, is capable of predicting if a lightning stroke will terminate on
the shielding system, the earth, or the protected element of the facility. One of the methods
based on the electrogeometric model is known as the rolling sphere technique. The rolling
sphere technique [B51] involves rolling an imaginary sphere over the surface of the earth up

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to the substation. The sphere rolls up and over all earth potential structures, lightning masts,
and shield wires. A piece of equipment is protected from direct strokes if it remains outside
the curved surface of the sphere because it is being elevated by shield wire or masts. The
radius of the sphere and the stroke attractive distance are determined by the assumed stroke
current in the equation of the electrogeometric model. Several approaches [B32], [B34],
[B35], [B41] to shielding switchyard from direct strokes have been based on the rolling
sphere technique and the geometric model. A comprehensive guide to these methods of
designing direct stroke shielding of substations is being developed by the IEEE Substation
committee [B52].

With two or more masts, the protective zone of each is increased somewhat in the area
between them. This may be considered as an increase in the angle (made with the vertical) of
the side of each protective cone that lies between two masts. With the usual spacings between
masts, this angle may increase to 60 degrees. It is recommended that all overhead lines enter-
ing the substation be protected by a grounded shield conductor(s) for a distance of at least
one-half mile (800 m) from the substation. These shielding conductors should be grounded at
each pole through as low a ground resistance as it is practicable to obtain, and they should be
connected to the ground grid at the substation. Low ground resistance is particularly impor-
tant for the ground connection at the first few poles adjacent to the substation.

A set of arresters is normally installed at the transformer terminals, since this is the most
expensive piece of equipment to protect. Additional arresters may be needed to protect
incoming line switches if they are expected to be in the open position for an extended period
of time. If not, the arresters installed at the transformer may, depending on the linear distance
between transformer and switches, protect all equipment inside the station. Assessment of
such need may be made with the assistance of aids such as Appendix C of IEEE Std C62.22-
1991. It will be found that usually rather significant separation distances can be tolerated (say
75-200 ft [23-61 m] — sometimes more) for station equipment 23 kV and above with full
BIL insulation. For equipment in the 15 kV class and below, actual practice usually has been
to avoid any appreciable separation distance. Low BIL dry-type transformers and rotating
machines require special attention, even in shielded environments.

Finally, a set of arresters adequately rated for the service is recommended for installation at
the remote end of the shielded section of the overhead line conductors. These arresters will
intercept the severe surges and dissipate a large portion of their transient energy to ground.
Only the attenuated voltage surge (perhaps one half or less of the original value) continues
along the shielded one-half mile line section to the station. The lessened duty on the station
surge-protective devices results in a corresponding reduction in the surge-voltage magnitude
arriving at the terminals of vulnerable apparatus.

6.7.3. 1.2 Non-effectively shielded substations

These may be defined as those substations that do not have the overhead shielding described
in the previous paragraphs. Such substations are likely to be small, medium- voltage (up to
and including 34.5 kV primary) installations entailing relatively simple circuit arrange-
ments— often only one incoming exposed line or one secondary exposed circuit, or both. In
such cases, incoming line arresters may suffice to protect the transformer if a minimum of

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circuit length, as defined in IEEE Std C62. 22-1991, is devoted to associated overcurrent pro-
tection and switching equipment (breaker or fused switch, for example). Otherwise, arresters
should be applied at the terminals of all transformers.

When a number of circuits are involved, the lightning-produced surge duties are divided
among them in inverse proportion to their surge impedances and, in general, the hazard is
reduced. Therefore, protective coordination should be established on the basis of the mini-
mum number of circuits in service. Also, it is important to ensure that sensitive apparatus is
not left isolated (from its surge protection) as a result of sectionalizing to accommodate an
unusual operating condition.

Since non-effectively shielded applications entail a much higher surge exposure, the proba-
bility may be such that arresters may be subjected to large lightning stroke currents and rates
of rise in areas of high lightning ground flash density. In these cases, the protective device
coordination should be based on a minimum of 20 000 A.

6. 7.3. 2 Metal-clad switchgear

In most installations, surge-arrester protection is not required at the metal-clad switchgear.
Often metal-clad switchgear has a limited exposure, that of a length of cable intervening
between the metal-clad and exposed line. Where the cable is of continuous metallic sheath,
figure 6-17 illustrates this case and provides a guide as to the possible need for an arrester at
the metal-clad switchgear. Note that an arrester is required at the line cable junction in any
case to protect the cable.

0 20 40 60 80 100 120 140 160 180 200

CABLE LENGTH <L) — SWITCHGEAR TO CABLE JUNCTION (ft)

Figure 6-17— Curves showing maximum permissible length of cable
for which arresters are not required in metal-clad switchgear
versus line-cable junction arrester clamping voltage

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Nonmetallic-sheathed cables have higher surge impedances than metallic-sheathed cables
and their use may necessitate the use of arresters at the switchgear (distribution class will suf-
fice). However, the installation of a neutral or ground wire in the duct with each three-phase
nonmetallic-sheathed cable provides very nearly the same surge impedance as continuous
metallic-sheathed cable and may be so considered for surge-protective purposes.

In many industrial installations the only exposure of the metal-clad switchgear to lightning
may be through a power transformer. When the power transformer has adequate lightning
protection on the exposed side opposite the switchgear, there is generally no necessity to pro-
vide arresters on the sheltered side of the transformer connected to the switchgear. Experi-
ence has shown that for the transformer sizes normally encountered in unit substations there
is usually not enough surge transfer through the transformer to be harmful to the metal-clad
switchgear.

6.7.3.3 Dry-type transformers

Standard dry-type transformers present relatively difficult lightning-protective problems due
to their usual low BILs compared to liquid-immersed transformers. When surge exposure is
by direct-connected overhead lines, arresters are required in direct shunt with the standard
dry-type transformer. Regarding applications of surge exposure through cable, figure 6-18
applies for standard dry-type transformers in the identical fashion that figure 6-17 applies for
metal-clad switchgear. With arresters comparable to those listed in tables 6-5 and 6-6, it will
be found that in many practical applications, even in this relatively shielded environment, the
line-cable junction arrester will not protect standard dry-type transformers against lightning-
produced traveling waves. Where an arrester is required at the transformer, a distribution-
class metal-oxide arrester or a riser pole arrester with a low equivalent front-of-wave voltage
rating may suffice provided its fault current withstand capability (i.e., pressure-relief rating)
is sufficient.

A somewhat less severe, although typical, surge exposure for dry-type transformers is
through another (supply) transformer (see figure 6-19). Any surges impinging on the primary
side of the supply transformer will be mollified somewhat as they are transferred through the
transformer to appear on its (the supply transformer’s) secondary. For the most used wye-
delta- and delta-wye-connected supply transformers, arresters are generally not required at
the dry-type transformer.

However, standard BIL dry-type transformers should be protected by arresters at or near their
terminals in applications where they can be subjected to surges due to current-limiting fuse-
blowing and/or other chopping effects of switching devices. Surge-protective capacitors are
also applied in rare situations to correct problem applications involving prior transformer fail-
ures and to enhance the protection of essential service applications, particularly where cable
length is inadequate to achieve transient voltage rate-of-rise control.

Dry-type transformers are available from several manufacturers with the same BIL as liquid-
immersed transformers. A choice may be considered of specifying the same BIL for dry-type
as for liquid-immersed types, as they both are subject to the same environment as far as

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0 50 100 150 200 250

CABLE LENGTH BETWEEN DRY-TYPE TRANSFORMER
AND CABLE JUNCTION (ft)

Note: Interpolate or extrapolate for BIL’s not shown.

Figure 6-18— Curves for determining maximum permissible length of cable
for which arresters are not required at standard dry-type transformer
versus line-cable junction arrester clamping voltage

impulses and transients are concerned, instead of providing the power system with additional
surge protection.

6.7.3.4 Overhead line protection (4-69 kV)

Historically, relatively little consideration has been given to the surge protection of open-wire
overhead distribution line insulation. This often results in line insulator flashover which must
be cleared by a fault-current-protective device, which in turn results in a momentary or
extended circuit interruption. Both the high gradient associated with insulator flashover and
service interruption are associated disadvantages of considerable significance to the more
sensitive plants, particularly all electronically automated industrial plants.

Analytical and test-model studies relating to overhead transmission and distribution circuits
[B24] have disclosed a so-called predischarge current effect in association with strokes to

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Ep/R

Figure 6-19— Curves showing maximum surge permissible at supply
transformer without requiring arrester at standard dry-type transformer

lines, which in effect tends to suppress surge overvoltages at midspan and concentrate them at
grounded poles. At grounded poles there is opportunity to install surge arresters on all phases
so that voltage stresses are relieved by the arrester-protective characteristics and thus prevent
flashover of line insulators. Actual utility company experience show that arresters protecting
each phase, at economically spaced intervals along the line, will often give improved protec-
tion and reduce the number of direct, as well as induced lightning stroke flashovers. This new
approach to line protection is also much less sensitive to footing resistance.

This should certainly be a consideration toward improving protection on overhead circuits
that serve sensitive industrial plants.

6.7.3.5 Aerial cable

Aerial cable is almost universally protected against direct lightning strokes by grounding the
messenger and sheath at every pole through a low value of ground resistance. This is to allow

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a lightning stroke to the messenger to drain off by current flow to earth without causing the
voltage of the messenger and sheath to rise excessively above the voltage of the cable con-
ductors. If an aerial cable joins an open-wire line, surge arresters should be installed at the
junction to protect the cable insulation against lightning surges that arrive over the open line.
The ground terminals of these arresters should be connected directly to the cable messenger
and sheath as well as to ground. Since the voltage and current surges produced in the messen-
ger of aerial cable by lightning stroke to the messenger result in voltage and current surges in
the cable conductors, it is generally recommended that aerial cable be considered the same as
open-wire lines as far as the protection of terminal equipment is concerned.

6.7.3.6 Overvoltage protection of shunt capacitor banks

Overvoltage protection should be considered whenever shunt capacitor banks are installed.
The possibility of overvoltages from lightning, switching surges, and temporary overvoltages
requires a detailed evaluation to determine the duty on arresters applied in the vicinity of a
shunt capacitor bank. Due to the low surge impedance of large high-voltage shunt capacitor
banks, it may not be necessary to add arrester protection against lightning beyond that which
already exists in the substation. However, additional protection may be needed to protect
equipment from overvoltages due to capacitor switching or the switching of lines or trans-
formers in the presence of capacitors (IEEE Std C62. 22-1991).

6. 7.3. 7 Overvoltage protection of high-voltage underground cables

In addition to the overvoltage protection at the junction between overhead lines and cables,
cables may require further consideration because of traveling wave phenomena and the
effects of distributed line charging capacitances (IEEE Std C62.22-1991).

6. 7.3. 8 Overvoltage protection of gas-insulated substations (GIS)

Overvoltage protection is required at the junction to overhead and may be required within the
GIS bus depending upon the arrangement and the length (IEEE Std C62. 22-1991).

6. 7.3. 9 Rotating machine protection

Incoming surges can be transferred through transformers by electrostatic and electromagnetic
coupling. Therefore, surge voltages can be experienced on the transformer secondary as well
as the generator terminals as a result of surge-voltage impulse on the transformer primary ter-
minals. This can occur even though the transformer is protected with arresters at the primary
terminals.

When high-voltage surges are internally generated, the standard protective circuit for rotating
machines consists of arrester and capacitor located near the machine terminals. The function
of the arrester is to limit the magnitude of the voltage to ground, while the capacitor length-
ens the time to crest and rate of rise of voltage at the machine terminals.

The basic winding design patterns of motors and generators involve rather large capacitance
coupling between the conductor of the winding of each coil and the grounded core iron that

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surrounds it. A fast rising surge voltage at the motor terminal lifts the potential of the terminal
turn, but the turns deeper in the winding are constrained (by this relatively large capacitance
from coil to ground) and delayed in their response to the arriving voltage wave. The result is a
greatly accentuated voltage gradient across the end-turns of the terminal coil that appears as
severe voltage stress on the turn-to-turn insulation of the terminal coil. Although the major or
ground wall insulation between conductors and ground is fairly thick, the turn insulation
within the coils is thin. Economical design dictates a thickness of no more than 0.005-
0.040 in, depending upon machine voltage rating. It is the protection of the turn insulation that
becomes critical in avoiding failure in multi-turn stator windings of ac motors and generators.

6.7.3.9.1 Machine winding impulse strength

It has already been observed that there are no established impulse standards on the insulation
structures for ac rotating machines. The machine impulse withstand envelope of figure 6-13
represents the most widely used curve for industrial applications of ac rotating machines.
This capability envelope, based on windings of form-wound coils with multi-turn construc-
tion, defines the expected winding impulse capability to be limited to surges whose fronts and
amplitudes lie below the indicated boundary (envelope). If a machine may be subjected to
impulse voltages of greater magnitude, it should be protected with arresters (to limit surge-
voltage magnitude) and surge-protective capacitors (to increase wave-front time) that will
ensure that the capability envelope is not exceeded by the impinging surge duty.

Impulse waves of lower magnitude, but having rise time less than 5 us, will primarily endan-
ger the turn insulation because of the nonuniform voltage distribution. Not only does 70-
100% of the impulse magnitude appear across the first coil connected to the incoming line,
but within that coil itself the voltage distribution is nonlinear, resulting in as much as half the
total coil impulse voltage appearing between the first two adjacent turns (|B8], [B25], [B44]).
By connecting a wave-sloping capacitor between each line terminal and ground affords pro-
tection against this condition [B 16].

The conventional method for wave-front, rate-of-rise protection of motors is shown in figure
6-20. A capacitor is installed line to ground on each motor phase conductor. The rate of rise
of the surge voltage across the motor winding terminals is limited by the charging rate of the
capacitor. Special protective capacitor units are designed for this purpose with low internal
inductance (table 6-7) that control the rate of rise of incident overvoltages to protect the turn-
to-turn insulation. Surge arresters then complete the rotating machine insulation protection to
ground by limiting the magnitude of the incident voltage wave.

6.7.3.9.2 Rotating machine surge protection practice

Much documentation exists relating to the surge protection of rotating machines. An ideally
protected installation requires the following:

a) A strictly effectively shielded environment

b) Arresters at terminals of machine

c) Surge capacitors at terminals of machine

d) Strict adherence to good grounding practices

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(b) Equivalent

Figure 6-20— Application of shunt-connected surge-protective
capacitors for wave-front control

Table 6-7— Capacitance of surge-protective capacitors
per line terminal connected line to ground

Rated motor voltage

650 V and less

2400-6900 V

11 500 V and higher

Capacitance, pF

1.0

0.5

0.25

Effective shielding requirements for stations have been defined previously in 6. 7. 3. 1.1. In the
case of rotating machines having overhead line exposure, either direct or through intervening
equipment (such as reactors, transformers, or cables), arresters are also applied out on the
exposed lines a distance of at least 1000-2000 ft to further reduce surge magnitude duties on
the more immediate surge-protection equipment.

The following example shows how the shunt-connected surge capacitor lessens the slope of
the voltage surge front and limits the crest voltage magnitude:

Figure 6-2 1 illustrates a voltage surge traveling along a branch cable circuit Z 0 = 50 £2 to a
4160 V motor. At the line terminal, which is connected to the motor terminals, a set of surge
protective capacitors (0.5 [iF per phase) are installed. By the use of surge arresters, the volt-
age crest already has been reduced, by a 5.1 kV MCOV arrester, to 16 kV.

The electrical equivalent circuit applicable to the travelling wave diagram of figure 6-21 is
shown in figure 6-22. The capacitor is charged by a 32 kV surge voltage through a resistance
of 50 Q. The driving voltage is considered as a rectangular wave of 32 kV acting for a dura-
tion of 6 fis.

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Figure 6-21 —Surge voltage wave traveling toward a motor
terminal on a 50 £2 surge impedance line

2Es = 32 kV 50n

Figure 6-22— Accurate lumped-constant equivalent circuit for analysis

The motor major insulation security will be concerned primarily with the magnitude of the
terminal voltage E c , while the turn insulation security will be concerned primarily with the
rate of rise of that voltage, dE c /dt.

The fundamental current-voltage relationships associated with a capacitor, starting from a de-
energized condition, are the following:

E c

Q p dt
C = C

dE c = dQ = /
dt dt C

When the capacitor is charged from a step-voltage source through a series resistor, as in
figure 6-22, the capacitor voltage builds up in accordance with

E c = 2E s (l-e~ t/t ')

where t' = RC, the circuit time constant, and

dE c i

— — (maximum) - — (maximum)
dt C

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In this specific problem, 2 E s = 32 kV, Z 0 = 50 Q, and C = 0.5I10) -6 . The RC product is
50 (0.5) (10r 6 = 25 (10)- 6 s.

The maximum input current to the capacitor I occurs at t = 0 when the surge voltage first
arrives at the capacitor and E C = 0. We then have the following:

2 3? 000

I = — - = = 640 A

Z„ 50

dE c j

-jj- (maximum) = —

640

0.5( 10) 6

= 1280( 10) 6 V/s = 1280 V/ps

For a surge-voltage duration of t = 5 /;s, the quantity e 1 is equal to
e -°' 2 = 0.8187
(1 - e^ 0 ' 2 ) = 0.1813

Thus at the end of the 5 pis interval, the capacitor voltage is
E C = 2E S (0.1813) = 32(0.1813) = 5.81 kV

In comparison with the 13 kV crest value of the motor high-potential test, the voltage level
developed across the capacitor (5.81 kV) is well below that level, and also well below the
protective level of the special 6 kV (5.1 MCOV) surge arrester. The rate of rise of voltage at
the motor terminal (maximum value) meets the criterion of at least 10 ps to reach the crest
level of the nameplate voltage.

In conclusion the following should be noted:

a) Had the circuit construction involved spaced conductors or open-wire lines, the surge
impedance would have been substantially greater, making the surge current values
lower, which in turn would account for lower values of capacitor voltage and lower
values of the rate of rise of the capacitor voltage.

b) Had the surge voltage been alternating, each subsequent half-cycle of surge current
flow would create cancellation effects in the capacitor voltage created by the previous
half-cycle.

c) A greater duration of unidirectional voltage surge would account for a greater voltage
across the capacitor, limited by the level 2 E s or the arrester protective level, which-
ever is lower.

d) The presence of series inductance in the capacitor circuit acts to deteriorate the wave-
sloping action of the surge capacitor, and even inductances of as little as a few micro-
henries can greatly impair performance ([B 16], Chapter 2).

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Actual practice indicates a very high percentage of motors above 4000 V are provided with
arresters and surge capacitors. Similarly, at least half of the 4000 V motors installations are so
equipped, while 2300 V motor installations are so equipped in only a minority of
applications.

In 1990, an Electric Power Research Institute (EPR1) report indicated that, in most cases,
motor and generator protection is not required. A 1992 IEEE publication [B 13], based on that
EPRI report, recommends “surge withstand standards be revised ... to reflect higher capa-
bility.” The IEEE publication refers to utility motors and utility environment throughout.
Motors for industrial and for utility applications are built to the same standard, but the indus-
trial environment is typically more severe, both electrically and non-electrically. Experience
is an important factor in the industrial practice of wide usage of surge capacitors, while utili-
ties make very little use of surge capacitors.

6.7.3.9.3 Special care required for proper installation of surge capacitors

Exploratory observations confirm the presence within shielded environments of voltage tran-
sients that approach arrester sparkover magnitudes and have exceedingly steep fronts (0.1 pis
front-time). Although lightning does not usually entail such steep fronts, certain switching
events do; for example, insulation breakdown, capacitor switching problems, or discharge of
high lightning current- to-ground. As established previously, separation distance between pro-
tective equipment and apparatus to be protected invokes (sometimes serious) depreciation of
protection. This is particularly true when steep wavefronts are involved. Surge capacitors, and
preferably arresters also, should be connected directly to the machine terminals so that added
inductance of the power cable circuit and of the surge capacitor lead will not interfere with
their action. This limits the arrester and capacitor total lead lengths to one or two feet, thus
requiring extreme care in the motor terminal box equipment arrangement.

Each application should be reviewed on its own. If several machines are fed from a common
bus, for example, it may be sufficient to connect arresters on the line side of the feeder circuit
breaker, placing only the capacitors at the machine terminals. Such practice generally
requires that the insulated conductors of each motor feeder circuit are continuously enclosed
in a grounded metallic raceway and that more than one feeder will be closed at the same time,
along with a careful analysis of the arrester-protective level and the capacitor wave-shaping
action as a function of the feeder length involved. A direct, low-impedance path between
machine winding and surge-protective devices must exist on both line and ground sides of the
circuit. A good ground connection to the machine frame is essential. Published standards do
not prescribe the size of such a connection, but the National Electrical Code (NEC) (ANSI/
NFPA 70-1993), Article 250-94, which specifies the size of the grounding electrode conduc-
tor, could be used as a guide. But, normally, the size of the protective-device ground terminal
serves as a guide; for capacitors, this typically permits a ground wire up to AWG No. 2.

When capacitor and arrester cases are solidly bolted to the conducting structure of a machine
terminal box or frame, such a ground wire may seem superfluous. However, it should not be
omitted. It should lead directly to a solid frame ground with the least possible number of
bolted joints intervening between the protective device and the machine stator. Such joints
risk having high resistance because of corrosion, bolt loosening, or paint. Furthermore, in

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some machines this wire may be the only ground provided, the reason being that users now
often specify that the surge-protective devices be mounted on ungrounded, insulated bases.
This stems from the NEMA requirement for disconnection of surge-protective devices from
machine leads when winding insulation is tested (NEMA MG 1-1993, Section 3.01.8). There
are at least three reasons for this recommendation:

a) Over-potential winding tests may damage capacitors,

b) Such a test may falsely indicate bad insulation because the overvoltage is discharged
to ground by an arrester,

c) Insulation resistance measurement by megohmmeter yields erroneous results because
of the leakage current bypassed to ground through the discharge resistor built into
every surge capacitor.

When a thorough preventive maintenance program includes such insulation tests once or
twice a year, the necessity of disconnecting the surge-protection devices from the line leads
becomes an expensive part of the program. Since it is desirable to maintain the permanent
line connections, isolation of the protective equipment can best be achieved by disconnecting
the equipment ground conductor. A readily removable conductor or link usually is provided
for ease in testing. After the test, this connection should be restored and tightened securely;
otherwise, protection may be lost.

6.8 References

This standard shall be used in conjunction with the following publications:

Accredited Standards Committee C2-1993, National Electrical Safety Code.

ANSI C37. 06-1987, American National Standard Preferred Ratings and Related Required
Capabilities for AC High-Voltage Circuit Breakers Rated on a Symmetrical Current Basis. 4

ANSI C50. 10-1990, American National Standard General Requirements for Synchronous
Machines.

ANSI C50. 13-1989, American National Standard Requirements for Cylindrical Rotor Syn-
chronous Generators.

ANSI C92. 1-1982, American National Standard on Insulation Coordination.

ANSI/NFPA 70-1993, National Electrical Code. 5

3 The National Electrical Safety Code (NESC) is available from the Institute of Electrical and Electronics Engineers,
Service Center, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331, USA.

4 ANSI publications are available from the Sales Department, American National Standards Institute, 1 1 West 42nd
Street, 13th Floor, New York, NY 10036, USA.

5 NFPA publications are available from Publication Sales, National Fire Protection Agency, 1 Batterymarch Park,
P.O. Box 9101, Quincy, MA 02269-9101, USA.

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IEEE Std C37.04-1979 (Reaff 1988), IEEE Standard Rating Structure for AC High-Voltage
Circuit Breakers Rated on a Symmetrical Current Basis (ANSI). 6

IEEE Std C37. 13-1990, IEEE Standard for Low- Voltage AC Power Circuit Breakers Used in
Enclosures (ANSI).

IEEE Std C37. 20-1987, IEEE Standard for Switchgear Assemblies Including Metal-Enclosed
Bus. 7

IEEE Std C37.41-1988, IEEE Standard Design Tests for High-Voltage Fuses, Distribution
Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and Accessories (ANSI).

IEEE Std C37. 91-1985 (Reaff 1991), IEEE Guide for Protective Relay Applications to Power
Transformers (ANSI).

IEEE Std C37. 96-1976, IEEE Guide for AC Motor Protection.

IEEE Std C57. 12.00-1987, IEEE Standard General Requirements for Liquid-Immersed Dis-
tribution, Power, and Regulating Transformers (ANSI).

IEEE Std C57. 12.01-1989, IEEE Standard General Requirements for Dry-Type Distribution
and Power Transformers Including Those with Solid Cast and/or Resin-Encapsulated
Windings.

IEEE Std C57. 12.90-1987, IEEE Standard Test Code for Liquid-Immersed Distribution.
Power, and Regulating Transformers; and Guide for Short-Circuit Testing of Distribution and
Power Transformers (ANSI).

IEEE Std C57. 12.91-1979, IEEE Standard Test Code for Dry-Type Distribution and Power
Transformers.

IEEE Std C57. 13-1978 (Reaff 1986), IEEE Standard Requirements for Instrument Trans-
formers (ANSI).

IEEE Std C57. 21-1990, IEEE Standard Requirements, Terminology, and Test Code for Shunt
Reactors Over 500 kVA (ANSI).

IEEE Std C62. 1-1989, IEEE Standard for Gapped Silicon-Carbide Surge Arresters for AC
Power Circuits (ANSI).

IEEE Std C62. 2-1987, IEEE Guide for the Application of Gapped Silicon-Carbide Surge
Arresters for Alternating-Current Systems (ANSI).

6 IEEE publications are available from the Institute of Electrical and Electronics Engineers, Service Center, 445 Hoes
Lane. P.O. Box 1331, Piscataway, NJ 08855-1331, USA.

7 This standard has been withdrawn and is out of print; however, photocopies can be obtained from the IEEE Stan-
dards Department. IEEE Service Center, 445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331, USA.

356

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IEEE
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IEEE Std C62.1 1-1987, IEEE Standard for Metal-Oxide Surge Arresters for AC Power Cir-
cuits (ANSI).

IEEE Std C62.22-1991, IEEE Guide for the Application of Metal-Oxide Surge Arresters for
Alternating-Current Systems.

IEEE Std C62.4 1-1991, IEEE Recommended Practice on Surge Voltages in Low- Voltage AC
Power Circuits (ANSI).

IEEE Std 100-1992, The New IEEE Standard Dictionary of Electrical and Electronics Terms
(ANSI).

IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and Commer-
cial Power Systems (IEEE Green Book) (ANSI).

NEMA MG1-1993, Motors and Generators. 8

6.9 Bibliography

[Bl] Abetti, P. A., “Bibliography on the Surge Performance of Transformers and Rotating
Machines,” AIEE Transactions (Power Apparatus and Systems), pt. Ill, vol. 77, pp. 1 1 50—
1164, 1958 (first supplement, vol. 81, pp. 213-219, 1962; second supplement, vol. 83,
pp. 847-855, 1964).

[B2] Abetti, P. A., “Survey and Classification of Published Data on the Surge Performance of
Transformers and Rotating Machines,” AIEE Transactions (Power Apparatus and Systems),
pt. HI, vol. 77, pp. 1403-1414, 1958.

[B3] AIEE Committee Report, “Impulse Testing of Rotating AC Machines,” AIEE Transac-
tions (Power Apparatus and Systems), pt. Ill, vol. 79, pp. 182-187, 1960.

[B4] AIEE Committee Report, “Power System Overvoltage Produced by Faults and Switch-
ing Operations,” AIEE Transactions, vol. 67, pp. 912-922, 1948.

[B5] AIEE Committee Report, “Switching Surges Due to Deenergization of Capacitative Cir-
cuits,” AIEE Transactions (Power Apparatus and Systems), pt. Ill, vol. 76, pp. 562-564, Aug.
1957.

[B6J Beeman, D. L., Ed., Industrial Power Systems Handbook. New York: McGraw-Hill,
1955.

[B7] Bewley, L. V., Traveling Waves on Transmission Systems, 2nd ed. New York: Wiley,
1951.

8 NEMA publications can be obtained from the National Electrical Manufacturers Association, 2101 L Street, NW,
Washington, DC 20037.

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[B8] Drake, C. W., Jr., “Lightning Protection for Cement Plants, Part I— Surge Voltages on
the Power System,” IEEE Transactions on Industry and General Applications, vol. IGA-4,
pp. 57-61, Jan./Feb. 1968.

[B9] Electric Utility Engineering Reference Book, Volume 3: Distribution System. Trafford,
PA: Westinghouse Electric Corporation, 1965.

[BIO | Electrical Transmission and Distribution Reference Book, Westinghouse Electric Cor-
poration. East Pittsburgh, PA, 1964.

[Bll| Fink, D. G., and Carroll, J. M., Standard Handbook for Electrical Engineers. New
York: McGraw-Hill, 1968.

[B 12J Greenwood, A. N., Electrical Transients in Power Systems. New York: Wiley, 1971 .

[B13] Gupta, B. K., Nilson, N. E., and Sharma, D. K., “Protection of Motors Against High
Voltage Switching Surges,” IEEE Transactions on Energy Conversion, 90 IC 558-7, T-EC,
Mar. 1992.

[B 14 [ Hendrickson, P. E., Johnson, L. B. and Schultz, N. R., “Abnormal Voltage Conditions
Produced by Open Conductors on Three-Phase Circuits Using Shunt Capacitors,” AIEE
Transactions (Power Apparatus and Systems), pt. Ill, vol. 72, pp. 1183-1193, Dec. 1953.

[ B 1 5 J Hunter, E. M., “Transient Voltages in Rotating Machines,” AIEE Transactions, vol. 54,
pp. 599-603, 1935.

[B16] IEEE Committee Report, “Coordination of Lightning Arresters and Current Limiting
Fuses,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-91, pp. 1075-1078,
May /June 1972.

[ B 1 7 J IEEE Std 399-1990, IEEE Recommended Practice for Power Systems Analysis (IEEE
Brown Book) (ANSI).

[B 1 8J IEEE Std 666-1991, IEEE Design Guide for Electric Power Service Systems for Gen-
erating Stations (ANSI).

[B19] IEEE Working Group Progress Report, “Impulse Voltage Strength of AC Rotating
Machines,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-100, No. 8,
pp. 4041-4053, Aug. 1981.

[B20] IEEE Working Group Report, “Voltage Rating Investigation for Application of Light-
ning Arresters on Distribution Systems,” IEEE Transactions on Power Apparatus and Sys-
tems, vol. PAS-91, pp. 1067-1074, May/June 1972.

[B21J Industrial Power Systems Data Book. Schenectady, NY: General Electric Company,
1961.

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[B22] Jackson, D. W., “Surge Protection of Rotating Machines,” IEEE Tutorial Course on
Surge Protection in Power Systems, Chapter 8, Pub 79EH0 144-6 PWR, 1979.

[B23] Johnson, I. B., Schultz, A. J., Schultz, N. R., and Shores, R. B., “Some Fundamentals
on Capacitance Switching,” AIEE Transactions (Power Apparatus and Systems), pt. Ill,
vol. 74, pp. 727-736, Aug^ 1955.

[B24] Kaufmann, R. H., “Nature and Causes of Overvoltages in Industrial Power Systems,”
Iron and Steel Engineer, Feb. 1952.

[B25] Kaufmann, R. H., “Overvoltages in Industrial Systems— How to Reduce Them by
Neutral Grounding,” Industrial Engineering News, May /June 1951.

[B26] Kaufmann, R. H., “Surge-Voltage Protection of Motors as Applied in Industrial Power
Systems.” General Electric Company, Publication GET-3019, Dec. 1971.

[B27] Lai, K. C., Lee, W. J., and Jackson, W. V., “Testing and Selecting Surge Suppressors for
Low- Voltage AC Circuits,” IEEE Transactions on Industry Applications, vol. 26, no. 6, pp.
976-982, Nov./Dec. 1990.

[B28] Lear, C. M., McCann, G. D., and Wagner, C. F., “Shielding of Substations,” AIEE
Transactions, vol. 61, pp. 96-100, Feb. 1942.

[B29] Lewis, W. W., The Protection of Transmission Systems Against Lightning. New York:
Wiley, 1950.

(B30] Liao, T. W., and Lee, T. H., “Surge Suppressors for the Protection of Solid-State
Devices,” IEEE Transactions on Industry and General Applications, vol. MA-2, pp. 44-52,
Jan./Feb. 1966.

[B31] “Lightning Protection of Metal-Clad Switchgear Connected to Overhead Lines,” Gen-
eral Electric Review, Mar. 1949.

[B32] Link, H., “Shielding of Modern Substations Against Direct Lightning Strokes,” IEEE
Transactions on Power Apparatus and Systems, vol. PAS-94, no. 5, pp. 1674-1679, Sept./
Oct. 1975.

[B33] Montsinger, V. M., “Breakdown Curve for Solid Insulation.” Electrical Engineering,
vol. 54, pp. 1300-1301, Dec. 1935.

[B34] Mousa, A. M., “A Computer Program For Designing the Lightning Shielding Systems
of Substations,” IEEE Transactions on Power Delivery, vol. 6, no. 1, pp. 143-152, Jan. 1991.

[B35] Mousa, A. M., “Shielding of High Voltage and Extra High-Voltage Substations,” IEEE
Transactions on Power and Systems, vol. PAS-95, no. 4, pp. 1303-1310, July/Aug. 1976.

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[B36] Nailen, R. L., “Transient Surges and Motor Protection,” IEEE Transactions on Industry
Applications, vol. IA-15, no. 6, pp. 606-610, Nov./Dec. 1979.

[B37] Niebuhr, W. D., “Protection of Underground Systems Using Metal-Oxide Surge
Arresters,” IEEE Rural Electric Power Conference, 1981 Conference Record, pp. 9-13,
CHI 654-3.

[B38] Petrov, G. N., and Abramov, A. I., “Overvoltage Stresses in the Turn Insulation of Elec-
trical Machinery Windings During Electromagnetic Transients,” Electrichestvo, NC 7,
pp. 24-31, Mar. 3, 1954.

[B39] Rudenberg, R., Electrical Shock Waves in Power Systems , Cambridge, MA: Harvard
University Press, 1968.

[B40] Sakshaug, E. C., Kresge, J. S., and Miske, S. A., Jr., “A New Concept in Station
Arrester Design,” IEEE Transactions on Power Apparatus and Systems, Paper F76-393-9, pp.
647-656, Mar./Apr. 1977.

[B41 ] Sargent, M. A., “Monte Carlo Simulation of the lightning Performance of Overhead
Shielding Networks of High-Voltage Stations,” IEEE Transactions on Power Apparatus and
Systems, vol. PAS-91, no. 4, pp. 1651-1656, July/Aug. 1972.

|B42] Sarris, A. E., “Lightning Protection for Cement Plants, Part II— Surge Voltages in the
Cement Plant,” IEEE Transactions on Industry and General Applications, vol. IGA-4,
pp. 62-67, Jan./Feb. 1968.

[ B43] Schultz, A. J., Van Wormer, F. C., and Lee, A. R., “Surge Performance of Aerial Cable,
Part I— Surge Testing of the Aerial Cable and Analysis of the Test Oscillograms,” AIEE
Transactions (Power Apparatus and Systems), pt. Ill, vol. 76, pp. 923-930, Dec. 1957.

[B44] Shankle, D. F., Edwards, R. F., and Moses, G. L., “Surge Protection for Pipeline
Motors,” IEEE Transactions on Industry and General Applications, vol. IGA-4, pp. 171-176,
Mar./Apr. 1968.

[B45] Skeates, W. F., Titus, C. H., and Wilson, W. R., “Severe Rates of Rise of Recovery
Voltage Associated with Transmission Line Short Circuits,” AIEE Transactions (Power Appa-
ratus and Systems), pt. Ill, vol. 76, pp. 1256-1266, Feb. 1958.

[B46] Stacey, E. M., and Selchau-Hansen, P. V., “SCR Devices— AC Line Disturbance, Isola-
tion and Short-Circuit Protection,” IEEE Transactions on Industry Applications, vol. IA-10,
pp. 88-105, Jan./Feb. 1974.

[B47] Van Wormer, F. C., Schultz, A. J., and Lee, A. R., “Surge Performance of Aerial Cable,
Part II— Mathematical Analysis of the Cable Circuits and Synthesis of the Test Oscillo-
grams.” AIEE Transactions (Power Apparatus and Systems), pt. Ill, vol. 76, pp. 930-942,
1957.

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[B48] Wagner, C. F., Electrical Transmission and Distribution Reference Book , 4th Ed.,
Westinghouse Electric Corp., 1964.

[B49] Walsh, G. W., “A New Technology Station Class Arrester for Industrial and Commer-
cial Power Systems,” IEEE Industrial & Commercial Power Systems Technical Conference,
1977 Conference Record, pp. 30-35, CHI 198-1.

[B50J Walsh, G. W., “A Review of Lightning Protection and Grounding Practices,” IEEE
Transactions on Industry Applications, vol. IA-9, no. 2, Mar./Apr. 1973.

[B51] Whitehead, E. R., “Mechanism of Lightning Flashover,” EEI Research Project RP 50,
Pub. 72-900, Illinois Institute of Technology, Feb. 1971.

[B52] Working Group E5 of Transmission Substations Subcommittee of the IEEE Substa-
tions Committee, “Guide for Direct Lightning Stroke Shielding of Substations,” Draft No. 5,
Mar. 1991.

[B53] Wright, M. T., and McLeay, K., “Interturn Stator Voltage Distribution Due to Fast
Transient Switching of Induction Motors,” IEEE Petroleum and Chemical Industry Confer-
ence, pp. 145-150, Conference Paper PCI-81-14.

361

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362

Chapter 7
Grounding

7.1 Introduction

All phases of the subject of grounding applicable to the scope of the IEEE Industrial and
Commercial Power Systems Department (I&CPSD) have been studied and documented in
IEEE Std 142-1991 [ B23] . That standard is the basic source of technical guidance for this
chapter. 1

Chapter 7 will identify and discuss those facets of grounding technology that relate to indus-
trial plants. The topics to be discussed are as follows:

a) Introduction

b) System grounding

c) Equipment grounding

d) Static and lightning protection grounding

e) Connection to earth

f) Grounding resistance measurement

Unless otherwise noted, the discussions in this chapter address low-voltage systems. (For
voltage system classifications, see Chapter 1, table 1-1.) When emergency and standby sys-
tems are involved, IEEE Std 446-1987 [B24], should be consulted.

7.2 System grounding

Alternating-current electric power distribution system grounding is concerned with the nature
and location of an intentional electric connection between the electric system phase conduc-
tors and ground (earth). The common classifications of grounding found in industrial plant ac
power distribution systems are as follows:

a) Ungrounded

b) Resistance grounded

c) Reactance grounded

d) Solidly grounded

There are several other methods for grounding electrical systems that are not covered in as
much detail as the above methods. The following methods are deviations or variations of the
above:

e) Corner-of-the-delta solidly grounded

f) Low-reactance

g) Mid-phase (solidly grounded) of a three-phase delta (commonly called center-tap)

'The numbers in brackets preceded by the letter B correspond to those in the bibliography in 7.8.

363

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The method of electric system grounding may have a significant effect on the magnitude of
phase-to-ground voltages that must be endured under both steady-state and transient condi-
tions. In ungrounded electric systems that are characteristically subject to severe overvoltage,
reduced useful life of insulation and associated equipment can be expected. Insulation fail-
ures usually cause system faults. In rotating electric machines and transformers where
insulation space is limited, this conflict between voltage stress and useful life is particularly
acute.

In addition to the control of system overvoltages, intentional electric system neutral ground-
ing makes possible sensitive and high-speed ground-fault protection based on detection of
ground-current flow. Solidly grounded systems, in most cases, are arranged so circuit protec-
tive devices will remove a faulted circuit from the system regardless of the type of fault. Any
contact from phase to ground in the solidly grounded system thus results in instantaneous iso-
lation of the faulted circuit and the associated loads. The experience of many engineers has
been that greater service life of equipment can be obtained with grounded-neutral than with
ungrounded-neutral systems. Furthermore, a very high order of ground-fault protection for
rotating machinery may be acquired by a simple, inexpensive ground overcurrent relay. The
protective qualities of rotating machine differential protection can be enhanced by grounding
the power supply system.

Where service continuity is required, such as for a continuous operating process, the high-
resistance grounded system can be used. With this type of grounded system, the intention is
that any contact between one phase conductor and a grounded (earthed) surface will not
cause the phase overcurrent protective device to operate (trip).

Overvoltages are minimized with any type of grounded electrical system. With high-resist-
ance grounded systems, like the solidly grounded system, greater service life of equipment
can be obtained, along with continuity of service.

For a detailed discussion and charts of the advantages and disadvantages, fault current, costs
comparisons, system voltages, and areas of applications of the different methods of system
grounding, see Catalog GET-3548 [B35],

The following practice is recommended for establishing the system grounding connection:

a) Systems used to supply phase-to-neutral loads must be solidly grounded as required
by the National Electrical Code (NEC) (ANS1/NFPA 70-1993).“ They are

120/240 V, single-phase, three-wire
208Y/120 V, three-phase, four-wire
480Y/277 V, three-phase, four-wire

b) Systems that may /could be resistance grounded are

480 V, three-phase, three-wire

480Y/277 V, three-phase, four-wire without phase-to-neutral loads
600 V, three-phase, three-wire

information on references can be found in 7.7.

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5000 volt class

2400 V, three-phase, three-wire
4160 V, three-phase, three-wire

8000 volt class

6900 V, three-phase, three-wire
15 000 volt class

12 000 V, three-phase, three-wire wye

12 470 V, three-phase, three-wire wye

13 200 V, three-phase, three-wire wye
13 800 V, three-phase, three-wire wye

7.2.1 Ungrounded systems

The ungrounded system is actually high-reactance capacitance grounded as a result of the
coupling to ground of every energized conductor. The operating advantage, sometimes
claimed for the ungrounded system stems from the ability to continue operations during a sin-
gle phase-to-ground fault, if sustained, will not result in an automatic trip of the circuit. There
will be merely the flow of a small charging current to ground. It is generally conceded that
this practice introduces potential hazards to insulation in apparatus supplied from the
ungrounded system (Beeman 1955 [B4]).

There is divided opinion among engineers about the degree of the overvoltage problem on
ungrounded systems (600 V and less) and the probability of its affecting the electrical service
continuity. Many engineers believe that fault locating is improved and insulation failures are
reduced by using some type of grounded power system. Others feel that under proper operat-
ing conditions the ungrounded system offers an added degree of service continuity not jeop-
ardized by insulation failures resulting from steady state and the probability of transient
overvoltages. Additional discussion of the factors influencing a choice of the grounded or
ungrounded system is given in Chapter 1 of IEEE Std 142-1991 [B23] and GET-3548 [B35].

As long as no disturbing influences occur on the system, the phase-to-ground potentials (even
on an ungrounded system) remain steady at about 58% of the phase-to-phase voltage value.
For the duration of the single phase to ground fault, the other two phase conductors through-
out the entire raceway system are subjected to 73% overvoltage. It is, therefore, extremely
important to locate the ground fault promptly and repair or remove it before the abnormal
voltage stresses produce insulation breakdown on machine windings, other equipment, and
circuits. Because of the capacitance coupling to ground, the ungrounded system is subject to
dangerous overvoltages (five times normal or more) as a result of an intermittent contact
ground fault (arcing ground) or a high inductive reactance connected from one phase to
ground or phase to phase.

Accumulated operating experience indicates that, in general purpose industrial power distri-
bution systems, the overvoltage incidents associated with ungrounded operation reduce the
useful life of insulation so that electric circuit and machine failures occur more frequently
than they do on grounded power systems. The advantage of an ungrounded system not imme-

365

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CHAPTER 7

diately dropping load upon the occurrence of a phase to ground fault may be largely elimi-
nated by the practice of ignoring a ground fault and allowing it to remain on the system until
a second fault occurs causing a power interruption. An adequate detection system with an
organized program for removing ground faults is considered essential for operation of the
ungrounded system. These observations are limited to ac systems. Direct-current system
operation is not subject to many of the overvoltage hazards present in ac systems. One final
consideration for ungrounded systems is the necessity to apply overcurrent devices based
upon their “single-pole” short-circuit interrupting rating, which can be equal to or in some
cases is less than their “normal rating.”

7.2.2 Resistance-grounded systems

Resistance-grounded systems employ an intentional resistance connection between the elec-
tric system neutral and ground. This resistance appears in parallel with the system-to-ground
capacitive reactance, and this parallel circuit behaves more like a resistor than a capacitor.
Resistance-grounded systems can take the forms of

a) High-resistance grounded systems

b) Low-resistance grounded systems

Investigations recommend that high-resistance grounding should be restricted to 5 kV class
or lower systems with charging currents of about 5.5 A or less and should not be attempted on
15 kV systems (Walsh 1973 [B37]), unless proper ground relaying is employed. The reason
for not recommending high-resistance grounding of 15 kV systems is the assumption that the
fault will be left on the system for a period of time. Damage to equipment from continued
arcing at the higher voltage can occur. If the circuit is opened immediately, there is no
problem.

In a high-resistance connection ( R < X co /3, where R is the intentional resistance between the
electric system neutral and ground, and X co /3 is the total system-to-ground capacitive reac-
tance), the overvoltage-producing tendencies of a pure capacitively grounded system will be
sufficiently reduced. In a low-resistance grounded system, phase-to-ground potentials are rig-
idly controlled, and sufficient phase-to-ground fault current is also available to operate
ground-fault relays selectively. X co is difficult to determine in a high resistance grounded sys-
tem without testing (Bridger 1983 [B7]), thus 5 A to 10 A is recommended for the phase-to-
ground fault current limitation.

The ohmic value of the resistance should be not greater than the total system-to-ground
capacitive reactance (X co /3). The neutral resistor current should be at least equal to or greater
than the system total charging current. For details on obtaining and testing the value of the
total system charging current. (See Bridger 1983 [B7J.)

High-resistance grounding provides the same advantages as ungrounded systems yet limits
the steady state and severe transient overvoltages associated with ungrounded systems. Con-
tinuous operation can be maintained. Essentially, there is minimal phase-to-ground shock
hazard during a phase-to-ground fault since the neutral is not run with the phase conductors
and the neutral is shifted to a voltage approximately equal to the phase conductors. There is

366

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no arc flash hazard, as there is with a solidly grounded system, since the fault current is lim-
ited to approximately 5 A.

Another benefit of high-resistance grounded systems is the limitation of ground fault current
to prevent damage to equipment. High value of ground faults on solidly grounded systems
can destroy the magnetic iron of the rotating machinery. Small winding faults on solidly
grounded systems may be readily repaired without replacing the magnetic iron. However, not
having to replace the lamination with equipment installed on high-resistance grounded sys-
tems, when a phase-to-ground fault occurs, is a benefit.

High-resistance grounded systems should require immediate investigation and clearing of a
ground fault even though the ground-fault current is of a very low magnitude (usually less
than 10 A). This low magnitude of continuous fault current can deteriorate adjacent insulation
or other equipment. As long as a phase-to-ground fault does not escalate into an additional
phase-to-ground fault on a different phase, resulting in a phase-to-phase fault and operating
the protective device, the continuous operation can continue. It is essential to monitor and
alarm on the first phase-to-ground fault. If the fault impedance is zero, solidly connected to
ground, the high-resistance system takes on the characteristics of a solidly grounded system
until the fault is located and repaired.

The key to locating a ground fault on a high-resistance grounded system is the ability to
injection a traceable ground signal to the faulted system. This fault-indicating system permits
fault location with the power system energized. An oversized, large opening, special clamp
on type ammeter is used. Some skill is required in finding the location of the fault. (See GET-
35548 [B35] for additional information.)

High-resistance grounding will limit to a moderate value the transient overvoltages created
by an inductive reactance connection from one phase to ground or from an intermittent-
contact phase-to-ground short circuit. It will not avoid the sustained 73% overvoltage on two
phases during the presence of a ground fault on the third phase. Nor will it have much effect
on a low-impedance overvoltage source, such as an interconnection with conductors of a
higher voltage system, a ground fault on the outer end of an extended winding transformer or
step-up autotransformer, or a ground fault at the transformer-capacitor junction connection of
a series capacitor welder.

Low-resistance grounding requires a grounding connection of a much lower resistance. It is
common to have 5 kV and 15 kV systems low-resistance grounded. The resistance value is
selected to provide a ground-fault current acceptable for relaying purposes. The generator
neutral resistor is usually limited for large generators to a minimum of 100 A and to a maxi-
mum of 1.5 times the normal rated generator current (Johnson 1945 [B28]). Typical current
values used range from 400 A (to as low as 100 A) on modern systems using sensitive toroid
or core balance current transformer ground-sensor relaying and up to perhaps 2000 A in the
larger systems using residually connected ground overcurrent relays. In mobile electric
shovel application, much lower levels of ground-fault current (50 to 25 A) are dictated by the
acute shock-hazard considerations. One final consideration for resistance-grounded systems
is the necessity to apply overcurrent devices based upon their “single-pole” short-circuit
interrupting rating, which can be equal to or in some cases less than their “normal rating.”

367

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CHAPTER 7

7.2.3 Reactance-grounded system

Reactance-grounded systems are not ordinarily employed in industrial power systems. The
permissible reduction in available ground-fault current without risk of transitory overvoltages
is limited. The criterion for curbing the overvoltages is that the available ground-fault current
be at least 25% of the three-phase fault current (X 0 /X^ s 10, where X 0 is the zero-sequence
inductive reactance, and Aj is the positive-sequence inductive reactance of the system). The
resulting fault current can be high and present an objectionable degree of arcing damage at
the fault, leading to a preference for resistance grounding. Much greater reduction in fault-
current value is permissible with resistance grounding without risk of overvoltage. One final
consideration for reactance grounded systems is the necessity to apply overcurrent devices
based upon their “single-pole” short-circuit interrupting rating, which can be equal to or in
some cases less than their “normal rating.”

7.2.4 Solidly grounded system

Solidly grounded systems exercise the greatest control of overvoltages but result in the high-
est magnitudes of ground-fault current. These high-magnitude fault currents may introduce
problems and generate other design problems in the equipment grounding system. Solidly
grounded systems are used extensively at all operating voltages. At high voltages, impedance
grounding sensing equipment costs needs to be considered. Large magnitude ground-fault
currents generally do not affect electrical equipment braced for that stress. Note that the pres-
sure relief duty of surge arresters will be affected by solidly grounded systems. Also, the
amount of insulation for medium voltage cable may be affected. Also, a large magnitude of
available ground-fault current is desirable to secure optimum performance of phase-over-
current trips or interrupting devices. The low phase-to-neutral driving voltage of the supply
system (346 V in the 600 V system and 277 V in the 480 V system) lessens the likelihood of
dangerous voltage gradients in the ground-return circuits even when higher than normal
ground-return impedances are present.

The solidly grounded system has the highest probability of escalating into a phase-to-phase
or three-phase arcing fault, particularly for the 480 and 600 V systems. The danger of sus-
tained arcing for phase-to-ground fault probability is also high for the 480 and 600 V
systems, and low or near zero for the 208 V system. For this reason ground fault protection
shall be required for systems over 1000 A (ANSI/NFPA 70-1993). A safety hazard exists for
solidly grounded systems from the severe flash, arc burning, and blast hazard from any phase-
to-ground fault.

7.2.5 System-grounding design considerations

There are three levels of conductor insulation for medium-voltage cables: 100, 133, and
173% levels. The solidly grounded system permits the use of 100% insulation level. When
the fault on the other system will raise the system voltage above normal during the time of the
fault, 133% insulation level should be specified if the fault is cleared within one hour. When
the fault will remain on the system for an indefinite time, 173% voltage level insulation
should be used (Bridger 1983 [B7]; NEMA WC5-1992 [B33]; GET-3548 [B35]).

368

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The intent of the preceding advisory recommendations is to promote broad application of the
fewest variety of system-grounding patterns that will satisfy the operational requirements of
industrial plant electric power systems in general. Even minor deviations in design practice
within a particular variety are to be avoided as much as possible. Nonetheless, it is admitted
that the list of recommended patterns is not all inclusive and hence is not to be regarded as
mandatory (IEEE Std 446-1987 [B24]).

Utility practices may justify a deviation from the patterns listed in previous paragraphs. Cir-
cumstances can arise that may well justify solid grounding with circuit patterns other than
those named in these recommendations. For example, when the power supply is obtained
from the utility company via feeders from a 4.16Y/2.4 kV solidly grounded substation bus,
the user will be justified in adopting that pattern. In such inevitable situations it is imperative
that adequate ground-return conductors be provided to minimize the inherent step-and-touch
potentials of high ground-fault currents associated with solidly grounded systems and to pro-
vide instantaneous ground fault relaying or equivalent to minimize the fault duration. See the
National Electrical Safety Code (NESC) (Accredited Standards Committee C2-1993), and
IEEE Std 80-1986.

Step voltage or step potential is the potential difference between two points on the earth’s sur-
face separated by a distance of one pace of a human (assumed to be 1 m [one meter]) in the
direction of the maximum potential gradient (IEEE Std 100-1992 [B22]). Within a substation
during a fault condition with a large current flow over and through the ground, a potential is
developed across the soil surface as a result of the soil’s resistance. Current flow through
earth from a lightning discharge will develop a potential also. Touch potential or touch volt-
age is the potential difference between a grounded metallic structure and a point on the
earth’s surface separated by a distance equal to the normal maximum reach, approximately
1 m. These potential differences, step or touch, could be dangerous and could result from
induction or fault conditions, or both.

Furthermore, should the user desire to serve 120 V single-phase, one-side-grounded, load cir-
cuits, there could be firm justification for solidly grounding the midpoint of one phase of a
240 V delta system to obtain a 240 V three-phase four-wire delta pattern. This is a utility
practice where a large single phase 120/240 V load exists and a small three-phase load is
required.

Ungrounded systems can be converted to solid, corner-grounded delta, thus gaining the
advantage of control of overvoltages and longer life of electrical equipment insulation. The
use of a 120 V three-phase delta system for general-purpose power could well justify solid
corner-of-the-delta grounding, although such systems are not designed today.

In designing the electric power supply system to serve electrically operated excavating
machinery, the existence of a greatly accentuated degree of electric- shock- voltage exposure
may justify the use of a system-grounding pattern employing a 25 A resistive grounding con-
nection (to establish a 25 A level of available ground-fault current). The achievement of keep-
ing personnel secure from dangerous electric-shock injury, both operators and bystanders,
may require the reduction in rotating-machine fault-detection sensitivity, which is therefore
sacrificed.

369

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There may be sound justification for the insertion of a reactor in the neutral connection of a
generator that is to be connected to a solidly grounded three-phase distribution system in order
to avoid excessive generator-winding current in response to phase-to-ground fault on the sys-
tem. The reactance of the neutral grounding reactor for generator grounding is calculated such
that current in any winding does not exceed three-phase short-circuit current and is not less
than 25% of three-phase short-circuit current. A minimum short-circuit current of not less than
25% of the three-phase short-circuit current is required to minimize transient overvoltages.

The foregoing examples clearly illustrate the need for design flexibility to tailor engineer the
system grounding pattern to cope with the unique and unusual situations. However, the deci-
sion to deviate from the advisory recommendations should be based on a specific engineering
evaluation of a need for that deviation.

7.3 Equipment grounding

Equipment grounding pertains to the system of electric conductors (grounding conductor and
ground buses) by which all non-current-carrying metallic structures within an industrial plant
are interconnected and grounded. The main purposes of equipment grounding are as follows:

a) To maintain low potential difference between metallic members, minimizing the pos-
sibility of electric shocks to personnel in the area (bonding);

b) To contribute to superior protective device performance of the electric system, safety
of personnel and equipment; and

c) To avoid fires from volatile materials and the ignition of gases in combustible atmo-
spheres by providing an effective electric conductor system for the flow of ground-
fault currents and lightning and static discharges to essentially eliminate arcing and
other thermal distress in electrical equipment.

All metallic conduits, cable trays, junction boxes, equipment enclosures, motor and generator
frames, etc., should be interconnected by an equipment grounding conductor system that will
satisfy the foregoing requirements. The rules for achieving these objectives are given in the
NEC and the NESC. These rules should be considered as minimum, and in some cases other
grounding and bonding means should supplement those requirements.

Previous practice for effecting equipment grounding within an industrial facility was to first
establish an external grounded loop, or a series of interconnected grounded loops, about the
building and then connect or bond every electrical device to that loop. While such practice
meets bonding rules, it does not always provide a path of least impedance. This happens
because the path for the ground fault is usually not adjacent to the phase conductor, and that
introduces additional reactance in the ground path.

In order to assure a low impedance for the grounding conductor, it is important that the
grounding conductor be run adjacent to the power cables with which it is associated; i.e., in
the same conduit or the same multi-conductor cable as the power conductors.

An equipment grounding conductor should be routed with the circuit phase conductors supply-
ing a circuit. This will achieve the desired low-impedance path necessary for safe operation.
Since the earth has an unknown resistance value, it should not be used for a return path.

370

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Std 141-1993

When an insulation failure occurs along an electric power circuit, causing an electrical con-
nection between the energized conductor and a metal enclosure, there exists a tendency to
raise the enclosure to the same electrical potential that exists on the power conductor. Unless
all such enclosures have been grounded, in an effective manner, an insulation breakdown will
cause dangerous electric potential to appear on the enclosure creating an electric shock haz-
ard to anyone touching it. The energy released during an arcing ground fault may be sufficient
to cause a fire or explosion or serious flash burns to personnel. Proper setting of ground relays
and intentional grounding of the metallic enclosures in a manner that assures the presence of
both adequate ground-fault current capacity and a low value of ground-fault circuit imped-
ance will interrupt the flow of ground-fault current and will thus minimize electric shock and
fire hazards (Kaufmann 1954 [B3 1 ]).

Figures 7-1 and 7-2 show typical system and equipment grounding for a three-phase electric
system. Solidly grounded, resistance-grounded, and ungrounded systems all have the same
equipment grounding requirements. The equipment grounding conductors are connected to
provide a low-impedance path for ground-fault current from each metallic enclosure or from
equipment to the grounded terminal at the transformer (figures 7-1 and 7-2). The impedance
of the complete ground-fault circuit should be low enough to ensure sufficient flow of
ground-fault current for fast operation of the proper circuit protective devices, and to mini-
mize the potential for stray ground currents on solidly grounded systems. To provide a
ground-fault current path of low impedance and adequate capacity, either the cross-sectional
area of the raceway must be large or a parallel grounding conductor must be run inside the
raceway (see figure 7-2). As shown in figures 7-3 and 7-4, equipment grounding conductors
are also required in resistance-grounded and ungrounded systems for personnel shock protec-
tion. The grounding conductors must provide paths of sufficient capacity to operate protective
devices when phase-to-phase or phase-to-ground faults occur at different locations on a
power system.

UNIT SUBSTATION
TRANSFORMER SWITCHGEAR

DISTRIBUTION

PANEL

STRUCTURAL STEEL
LOAD

HI ,

r~'

CIRCUIT PROTECTION

1-T

-xPSp 1

i x 1 | — „ I

FEEDER

CIRCUITS

1-0 o !
I ,

r c“p“l

BRANCH

CIRCUITS

<3 O-

XO jN

I— I

METALLIC
ENCLOSURES

f G
l_ H

SYSTEM „
GROUNDING

11 11 n 1

l \J n i\ J /i

-* RACEWAYS, ETC, ■— 4- - 1 EQUIPMENT L

• -* RACEWAYS, ETC
APPROVED FOR
GROUNDING

( 1

EQUIPMENT

GROUNDING

CONDUCTORS

■V

•

EARTH OR SOME CONDUCTING BODY
THAT SERVES IN PLACE OF EARTH

POTENTIAL EQUALIZING, STATIC AND
LIGHTNING PROTECTION GROUNDING

Figure 7-1 —Grounding arrangement for ground-fault protection in
solidly grounded system, three-phase, three-wire circuits

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CHAPTER 7

Figure 7-2— Fault-current path through ground-fault conductors in
solidly grounded system, three-phase, three-wire circuits

Figure 7-3— Grounding arrangement for ground-fault protection in
resistance-grounded system, three-phase, three-wire circuits

Figure 7-4— Grounding arrangement for ground-fault protection in
ungrounded system, three-phase, three-wire circuits

372

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Economics and operating requirements have resulted in an increasing number of industrial
plants owning and operating the transformer substation connecting the industrial plant with
the electric utility. In addition to providing the proper equipment grounding in such a sub-
station, step and touch potentials also must be maintained at a safe level. An appropriately
designed grounding mat has traditionally served the purposes of providing for both the safety
of personnel in and near the substation and proper grounding of the substation equipment.
Empirical methods have been used extensively in the past for ground mat design due to the
great number of calculations required for a perfectly rigorous ground mat analysis. Computer
programs have added to the accuracy and ease of ground mat design. Persons involved in sub-
station grounding are advised to refer to IEEE Std 80-1986 [B20] for substation grounding
design requirements and detailed calculation procedures. See Meliopous 1988 [B32].

The ground grid of the utility substation is often interconnected with the industrial plant
grounding system, either intentionally by overhead service, or a buried ground wire or unin-
tentionally through cable tray, conduit systems, or bus duct enclosures. As a result of this
interconnection, the plant grounding system is elevated to the same potential above remote
earth as the substation grid during a high-voltage fault in the substation. Dangerous surface
potentials within an industrial plant as well as within the substation also must be prevented.
In certain cases, hazardous surface potentials may be eliminated by effectively isolating the
substation ground system from the plant ground system. In most cases, integrating the two
grids together and suitably analyzing both systems for step and touch potentials have reduced
these potentials to acceptable levels.

7.3.1 Computer grounding

A new IEEE Color Book, IEEE Std 1 100-1992 (the Emerald Book) [B26], which deals with
powering and grounding sensitive electronic equipment, has recently been published.

Computers are used in industry process control, accounting, data transmission, etc. Computer
system grounding is very important for optimum performance. It requires coordination with
power-conditioning equipment, communication circuits, special grounding requirements of
computer logic circuits, and surge arresters.

Computer manufacturers specify grounding techniques for their equipment but some are
inconsistent, do not follow known grounding practices, or violate the requirements of the
NEC and OSHA. Mutually acceptable solutions can be achieved by returning to fundamental
principles of grounding. See IEEE Std 1100-1992 [B26] and IEEE Std 142-1991 [B23],

Computer system grounding accomplishes multiple functions, such as safety to operating
personnel, a low-impedance fault-return path, and maintenance of the equipotential ground of
all units of a computer system.

Connecting the frames of all units of a computer system to a common point should ensure
that they stay at the same potential. Connecting that point to the ground should ensure that the
equipotential is also ground potential. These objectives are achieved when the units are con-
nected to an ac power source and include a safety equipment ground conductor in each cable

373

IEEE

Std 141-1993

CHAPTER 7

or conduit that carries power that comes from a common source (IEEE Std 142-1991 [B23];
IEEE Std 1100-1992 [B26]; Kalbach 1981 [B29]).

However, when there is more than one power source, each with its separate ground, this sys-
tem will create “noise” currents in the grounding systems that are connected to the units of
the computer system. In such cases, a signal reference grid may be used. This grid may be a
large sheet of copper foil installed under the computer or a 2 ft by 2 ft mesh of copper con-
ductors laid out on the subfloor (see figure 7-5) to equalize the voltage over a broader fre-
quency range. All computer units should be bonded to this grid in addition to the equipment
ground conductor. The signal reference grid is grounded to the same central grounding point
as the frames of the system components.

NOTES:

( Green wire is connected to the system ground through point G.)

Figure 7-5— Computer units connected to
signal reference grid and to ac ground

An alternative signal reference grid could be a raised floor metal supporting structure, which
is electrically conducting and suitably bonded at all joints. All precautions outlined in IEEE
Std 142-1991 [B23] and Kalbach 1981 [B29] should be followed for the application of a sig-
nal reference grid.

Preferred methods of grounding the following types of equipment are given in detail in Chap-
ter 2 of IEEE Std 142-1992 [B23]:

a) Structures

b) Outdoor stations

c) Large generators and motor rooms

d) Conductor enclosures

e) Motors

f) Portable equipment

g) Surge/lightning protective devices

374

GROUNDING

IEEE
Std 141-1993

In many specific types of installations, the applicable national, state, or local electrical codes
prescribe such grounding practices as a mandatory requirement.

7.4 Static and lightning protection grounding

7.4.1 Static grounding

Industrial plants handling solvents, dusty materials, or other flammable products often have a
potentially hazardous operating condition because of static charge accumulating on equip-
ment, on materials being handled, or even on operating personnel.

The discharge of a static charge to ground or to other equipment in the presence of flammable
or explosive materials is often the cause of fires and explosions, which result in substantial
loss of life and pr

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